WESTERN GAS RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)

Title of Each Class		Name of Exchange on Which Registered
Common Stock, $0.10 par value		New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

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 o No ý

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

The aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2005 was $2,274,327,532. The number of shares outstanding of the only class of the registrant's common stock, as of March 8, 2006, was 75,450,065.

Information required by Part III of this Report (Items 10, 11, 12, 13 and 14) 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.

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

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):

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

Double Proved Natural Gas Reserves and Equity Production of Natural Gas from the level at December 31, 2001 over a five-year period. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin Coal Bed Methane play, or CBM, and development in the Greater Green River and San Juan Basins, and actively seek to add other core natural gas development projects. Overall, at January 31, 2006, we held drilling rights on approximately 1.7 million net acres in these and other Rocky Mountain basins. At December 31, 2005, we had proved developed and undeveloped reserves of approximately 921 billion cubic feet equivalent, or Bcfe, of which 43% are proved developed producing and proved developed non-producing reserves. In total, we have increased our proved developed and undeveloped reserves by approximately 94% from December 31, 2001. During 2005, our production of natural gas as compared to 2004 increased by 14% to 63.0 Bcfe. In total, this represents an increase of approximately 74% in our average equity production of natural gas from 2001 levels. We currently anticipate a 17% to 22% growth in our equity production of natural gas in 2006. This increase will allow us to achieve our goal to double equity production of natural gas from the level at December 31, 2001. In the Powder River Basin, our future growth lies in over 7,000 potential well locations and 14,000 potential recompletions of multiple coal seams in the Big George, Wyodak and related coals if the play is fully successful. In the Greater Green River Basin, our reserve potential is in the development of locations on our leasehold on the Pinedale Anticline and in the Jonah Field, which in some areas have been approved for down-spacing to one well per 10 acres. This development targets sandstone reservoirs in the Lance and Mesa Verde formations.

areas outside the Rockies, including western Canada, where we can leverage our related exploration, production and gathering expertise.

Meet or Exceed Throughput Projections in our Midstream Operations. To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections, expansion or acquisition of gathering or processing systems and the consolidation of existing facilities. We also seek growth opportunities for gathering and processing through our development of new gas reserves. Our midstream operations provide us with steady throughput volumes and significant cash flow that we can in turn reinvest in new growth opportunities in this or other segments of our operations. In 2005, the throughput volume at our gathering and processing facilities averaged 1.42 billion cubic feet, or Bcf, per day and segment operating profit contributed by these facilities was $237.6 million. We currently anticipate 12% growth in our throughput volumes at our gathering and processing facilities in 2006.

Our gathering and processing operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather, process or treat natural gas produced on acreage dedicated by third parties to us or acreage that we are developing. We contract to provide these services for production from newly developed acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering, processing or treating at our facilities. Although some of our plants have experienced natural declines in connected reserves, overall we have been successful in connecting additional reserves to more than offset these declines. At December 31, 2005, the estimated future natural gas production connected to our gathering, processing and treating facilities totaled approximately 4.5 trillion cubic feet, or Tcf. This is based on an internal review of historical facility throughput gas volume, our interpretation of expected declines from existing connections, and assumes that there are no new well connections to our facilities. We will continue to evaluate investments in expansions or acquisitions of assets that complement and extend our core natural gas gathering, processing, treating and marketing businesses and new growth projects in the Rocky Mountain, West Texas and Mid-continent region.

Optimize Annual Returns. To optimize our annual returns, we will focus our efforts in our primary operating areas in the Powder River and Greater Green River Basins, the Anadarko Basin in Oklahoma, the Permian Basin in West Texas, and the San Juan Basin. We review the economic performance and growth opportunities of each of our assets to ensure that a satisfactory rate of return is achievable. If an asset is not generating targeted returns or is outside our core operating areas, we explore various options, such as integration with other Western-owned facilities or consolidation with third-party-owned facilities, dismantlement, asset trades or sale. Consolidations and joint ventures allow us to increase the throughput of one facility while reducing the capital invested in, and the operating costs of, the consolidated assets. For example, in the third quarter of 2005, we consolidated the operations of our Red Desert, Wamsutter and Patrick Draw facilities in Wyoming in order to reduce operating costs and enhance recoveries of NGLs. Also, we routinely evaluate our business for methods to reduce our operating and administrative costs, including the implementation of automation and the use of information technology.

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

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

information on our website, other links contained in our website and our website are not incorporated into this Report.

In general, in order to maintain a strong balance sheet, our general goal is to limit our capital expenditures in any single year to 110% of the projected cash flow generated by our operations for that year. In some years, however, we expect that we will exceed this limitation based on the growth opportunities available to us. In 2006, we anticipate capital expenditures of approximately $665.8 million. The 2006 capital budget is presented in the following table (dollars in thousands).

Type of Capital Expenditure		2006 Capital Budget
Gathering, processing, treating and pipeline assets		$	185.0
Exploration and production and lease acquisition activities			326.2
Acquisition of CBM properties			136.7
Information technology and other items			4.5
Capitalized interest and overhead			13.4

	Total	$	665.8

The majority of our capital expenditures are expected to be in the Powder River Basin CBM, development and in the Greater Green River Basin. In the Powder River Basin CBM development, we plan to invest $343.3 million, or 52% of our total 2006 capital program. Of this amount, $136.7 million is planned to be spent for a March 2006 acquisition of CBM properties, $135.5 million is planned to be spent on our share of drilling approximately 900 gross wells and for production equipment and undeveloped acreage and $71.1 million is planned to be spent for gathering lines and installation of additional compression units.

In February 2006, we signed an agreement for the purchase of certain CBM properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming from an undisclosed seller for approximately $136.7 million before adjustments. Closing is expected to occur on or before March 15, 2006 and will be funded with amounts available under our revolving credit facility. The purchase price includes the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. Approximately 70 of the drilled wells are currently dewatering and the remaining 40 wells are awaiting hookup.

In the Greater Green River Basin, we expect to invest $146.6 million, or 22% of the total 2006 capital expenditure program. We plan to spend $98.8 million to participate in 146 gross wells, 120 of which are in the rapidly developing Pinedale Anticline area and 12 of which are in the Jonah Field, and $47.8 million to expand gathering and compression services.

The remaining $175.9 million of our 2006 capital spending program is expected to be spent as follows: $66.1 million for well connections, expansions, maintenance and upgrade projects in our other midstream operations, $91.9 million for other upstream projects primarily consisting of exploration activities including lease acquisition and exploratory drilling, $13.4 million for capitalized interest and overhead and $4.5 million for information technology and other items. Overall, we expect to spend $22.2 million on maintenance and upgrade projects for existing midstream facilities.

A vital aspect of our long-term business plan is to double proved natural gas reserves and equity production of natural gas from the level at December 31, 2001 over a five-year period. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder

River Basin CBM development, the Greater Green River Basin, and the San Juan Basin. Each of our existing upstream core projects in these areas are substantially integrated with our midstream operations. In other words, in these areas, we provide substantially all the gathering, compression, processing, marketing or transportation services for our own production and also provide these services for third-party operators. Additionally, we are actively pursuing new exploration, development and producing property acquisition opportunities in unconventional gas developments in the United States and Canada.

Revenues derived from our producing properties comprised approximately 10%, 9% and 7% of our consolidated revenues for the years ended December 31, 2005, 2004 and 2003, respectively. The segment operating profit (revenues and earnings from equity investments less product purchases and operating expenses) derived from our producing properties comprised approximately 48%, 42% and 40% of consolidated operating profit for the years ended December 31, 2005, 2004 and 2003, respectively. We expect both the revenues and operating profit derived from our producing properties to continue to increase commensurately with our production growth.

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin CBM reserves and expand the associated gathering system in northeast Wyoming. Our net production sold from the Powder River Basin CBM averaged 116 MMcf per day in 2005.

At December 31, 2005, we had established proved developed and undeveloped reserves totaling 339 Bcfe, net, on a portion of this acreage, 59% of which are proved and developed. Overall, this represented a 9% increase in proved reserves as compared to December 31, 2004. Proved reserves at December 31, 2005 included 266 Bcf from the Big George and related coals, a 49% increase from year-end 2004. Our production from the Big George coal continues to increase and averaged 150 MMcf per day gross, or 58 MMcf per day net, in December 2005 from the All Night Creek Unit, Pleasantville, SG Palo, Bullwhacker, Schoonover, Savageton, Powder Valley and Kingsbury Unit areas. In these development areas and our areas of exploration, as of December 31, 2005, we had 1,054 gross Big George wells producing gas, 492 gross Big George wells dewatering and 807 gross Big George wells drilled and awaiting connection to begin dewatering. Typically a period of dewatering lasting from a few to thirty-six months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering, and to classify the reserves as proved.

Drilling in the Powder River Basin is dependent on the receipt of various regulatory permits, including Bureau of Land Management, or BLM, drilling permits, Wyoming Department of Environmental Quality, or DEQ, water discharge permits, and the Wyoming State Engineer's Office reservoir permits. Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area. Water management techniques utilized by us, and approved by the

DEQ on a site-specific basis, have included containment or treating. In order to facilitate the processing of our water discharge permit applications, on the west side of the basin, and in advance of the receipt of final requirements of the DEQ, we have installed and are evaluating various types of water treatment facilities to test their effectiveness. We are treating the water produced in some areas of the basin and, with the approval of the DEQ, discharging this water into the Powder River. We believe many of the future developments in the Big George coal will likely require water treatment facilities. These treating operations have added and will continue to add to the cost of development and operations in these areas. We continue to evaluate several options for water treatment and are working with the governmental agencies to identify effective and cost efficient methods. We are also evaluating the feasibility and cost of installing and operating a water pipeline to transport and dispose of produced water away from the development areas. Depending upon the type of water treatment system that proves to be the most effective and cost efficient, we may incur additional costs and/or delays in production and access to materials required to deploy these facilities in all our operating areas.

Excluding costs related to our planned March 2006 acquisition of certain CBM properties, our 2006 capital budget for the Powder River Basin CBM project is approximately $135.5 million for drilling, production equipment, leasehold acquisition and water treatment of approximately 900 gross wells. In 2006, in the Big George and related coals, we plan to participate in the drilling of 800 gross wells, or 400 net wells, and in the Wyodak and related coals, we plan to participate in an additional 100 gross wells, or 50 net wells. Together with our co-developer, we have received 41% of drilling permits and 53% of water discharge permits required for our drilling program for 2006. There is, however, no assurance as to the future timing of the receipt of drilling and water discharge permits, any changes in regulations governing drilling and water discharge, restrictions placed on water discharge and/or quality by Wyoming or other states, the success of our drilling program, the availability of materials used in water treatment, or the dewatering time as our development progresses into the western and northern parts of the Powder River Basin. During 2005, we expended approximately $120.1 million in the Powder River Basin CBM project for drilling costs, production equipment and lease acquisitions.

In 2003, the BLM issued the final Record of Decision, or ROD, for the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS. The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation prior to the BLM granting a drilling permit. A number of cases have been filed by environmental groups against the BLM in Wyoming disputing the validity of the EIS and ROD. Due to our interests in developing federal leases in the Powder River Basin, we are an intervenor defendant in these cases. In one of these cases filed in the United States District Court of Montana, the court was asked to address the adequacy of the Montana Powder River Basin ROD and whether the BLM should have issued a single EIS for the Powder River Basin. Under an Order dated March 4, 2005, the court found that a single EIS for the Powder River Basin is not required under the National Environmental Policy Act, or NEPA. This Order was subsequently appealed. As these cases proceed, the BLM, in the event of any adverse rulings, may be required to perform further environmental analysis and, in addition, could be ordered to cease issuing drilling permits until it has completed such further analysis. Consequently, our ability to receive permits and develop our leases may be delayed or restricted by the outcome of these cases.

Pinedale Anticline and Jonah Fields. Our exploration and production assets in the Green River Basin of southwest Wyoming are located in the Pinedale Anticline and Jonah Field areas. During 2006, we expect to participate as a non-operating working interest in the drilling of 132 gross wells, or approximately 13 net wells, on the Pinedale Anticline and in the Jonah Field. Our capital budget for 2006 in the Pinedale Anticline area provides for expenditures of approximately $78.2 million for drilling costs and production equipment. During 2005, we expended approximately $63.5 million in the Pinedale Anticline and Jonah Field for drilling costs and production equipment.

At December 31, 2005, we had established proved developed and undeveloped reserves in the Pinedale Anticline and Jonah Fields totaling 529 Bcfe, net, 29% of which are proved developed producing and proved developed non-producing reserves. This represented an overall 19% increase in proved reserves as compared to December 31, 2004. In total, as a result of our drilling, proved undeveloped locations resulting from drilling, and the increased drilling density discussed below, our proved reserves increased by a net 97.8 Bcfe in this play in 2005. Partially offsetting this increase was production of 14.9 Bcfe during the year.

Historically, drilling in the Jonah Field and on the Pinedale Anticline has been allowed on one well per 40-acre tract. More recently, the State of Wyoming has approved the drilling of two wells per 40-acre tract on most of the Pinedale Anticline and four wells per 40-acre tract in the Jonah Field and on a portion of the Pinedale Anticline. As a result, we have significantly increased our number of drilling locations in these areas.

San Juan Basin. We continue to explore and develop our acreage position in the San Juan Basin in northwest New Mexico. During 2005, we produced and sold an average of 11 MMcfe per day from this acreage. Proved developed and undeveloped reserves as of December 31, 2005 totaled approximately 28 Bcfe. This represented an overall 8% increase in proved reserves as compared to December 31, 2004. Our 2006 capital budget in this area provides for expenditures of approximately $11.1 million for our participation in the drilling of 13 gross and net development wells and 60 recompletions or workovers of the previously drilled wells. During 2005, we expended approximately $24.1 million in the San Juan Basin for drilling costs and production equipment.

Sand Wash Basin. We continue to explore and develop our acreage position in the Sand Wash Basin in northwest Colorado, located in the southeastern Greater Green River Basin. During 2005, we produced and sold an average of 5 MMcfe per day from this acreage. At December 31, 2005, we had established proved developed and undeveloped reserves totaling 24 Bcfe on a portion of this acreage.

At December 31, 2005, we owned approximately 112,000 net oil and gas leasehold acres in the Sand Wash basin. The majority of this acreage is in the exploration phase and will be evaluated in 2006 and in future years. In 2005, approximately $7.5 million was spent in this area. Our 2006 capital budget in this area provides for expenditures of approximately $11.9 million for our participation in the drilling of six gross and net development wells, four workovers and two exploratory wells.

Exploration. We continue to seek to add additional upstream core projects that are focused on unconventional gas developments in the United States and Canada. We will utilize our expertise in exploration and low-risk development of unconventional gas reservoirs including tight-gas sands and coal bed methane to evaluate acquisitions of additional leaseholds, proved and undeveloped reserves, or companies with operations primarily focused on unconventional gas developments. Through December 31, 2005, we have acquired the drilling rights on approximately 998,000 net acres in other Rocky Mountain and Canadian basins and continue to expand our leasehold positions.

Western Canadian Sedimentary Basin. This biogenic, low permeability, or "tight" sand gas play is located in the southeastern area of the Western Canadian Sedimentary Basin located in southwestern Saskatchewan. In this play, as of December 31, 2005, we have acquired the drilling rights on approximately 40,000 gross or 39,000 net acres. During 2005 we completed 18 gross and net wells on this acreage. We began gas production from these wells in January 2006. Our 2006 capital budget in Canada provides for expenditures of approximately $33.2 million for our participation in the drilling of 60 gross and 49 net exploratory wells.

Red Desert, Washakie and Uinta Basins. The Red Desert and Washakie Basins are located in the eastern portion of the Greater Green River Basin. The Uinta Basin is located in the northern portion of Utah. In these areas, as of December 31, 2005, we have acquired the drilling rights on approximately

60,000 gross acres, or approximately 42,000 net acres. We drilled three wells in 2005 in these areas and plan to drill nine wells in these areas in 2006.

Fort Worth and Delaware Basins. We began leasing in these areas in 2005 targeting Barnett and Woodford shale gas plays. In these areas, as of December 31, 2005, we have acquired the drilling rights on approximately 38,000 gross acres, or approximately 35,000 net acres. We expect to drill five wells in these areas in 2006.

Central Montana Development. This development is located in the north central part of Montana. In this area, as of December 31, 2005, we have acquired the drilling rights on approximately 639,000 gross acres, or approximately 557,000 net acres. During 2005, we drilled three wells and are evaluating core samples and developing completion techniques to further test these wells.

Denver-Julesburg Basin. This Niobrara gas play is located in the northeastern area of the Denver-Julesburg Basin in northeast Colorado and southwest Nebraska. In this play, as of December 31, 2005, we have acquired the drilling rights on approximately 393,000 gross acres, or approximately 339,000 net acres. During 2005, we drilled seven gross and net wells in this basin. At December 31, 2005, these wells were producing approximately 360 Mcf per day. During 2006, we will continue to evaluate this play to determine whether we will further develop this acreage or seek a buyer for it.

During 2005, our capital expenditures in the exploration areas, other than Canada, totaled $23.1 million. Our capital expenditure budget for 2006 in the exploration areas, excluding Canada, totals $56.2 million, primarily for our participation in drilling activities, seismic surveys and leasehold acquisition.

Drilling Results. The following table sets forth the number of wells we completed during each of the last three years in each of our major producing areas. This information should not be considered to be indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are producing wells and wells capable of production.

During the years ended December 31, 2005, 2004 and 2003, we expensed $1.8 million, $320,000 and $1.9 million of costs related to dry exploratory wells.

Production and Reserves Information. The following table provides a summary of our net annual production volumes:

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

Netherland, Sewell & Associates, Inc, or NSAI, prepared the reports for proved reserves for 2005, 2004 and 2003. See additional discussion about reserves in Item 1A. "Risk Factors."

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

Gas Gathering, Processing and Treating. At December 31, 2005, we operated a variety of gathering, processing and treating facilities, or plant operations, with approximately 11,000 miles of gathering lines, as presented on the Principal Gathering, Processing and Treating Facilities Table set forth below. These facilities are primarily located in five states and, at December 31, 2005, had a combined throughput capacity of approximately 3.4 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. Five of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and three of our plants are capable of processing and treating natural gas containing hydrogen sulfide or other impurities that require removal prior to delivery to market pipelines. In addition to our integrated upstream and midstream operations in the Powder River, Greater Green River, and San Juan Basins, our core assets include our gathering systems and 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.

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, treating facility or a pipeline. At a processing plant, we compress the natural gas, extract raw NGLs and may treat the remaining dry gas in order to meet pipeline quality specifications.

We obtain dedicated acreage and natural gas supplies under contract in an effort to maintain or increase throughput levels to offset natural production declines of connected wells. We obtain these natural gas supplies by connecting additional wells, purchasing existing systems from third parties and through internally developed projects or joint ventures. Historically, while individual plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines. At December 31, 2005, the estimated future natural gas production connected to our gathering, processing and treating facilities totaled approximately 4.5 Tcf. This is based on an internal review of historical facility throughput gas volume, our interpretation of expected declines from existing connections, and assumes that there are no new well connections to our facilities.

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, gathering, treating or processing of natural gas for periods ranging from one month to 20 years or in some cases for the life of the oil and gas lease. Approximately 81% of our plant facilities' gross margin, or revenues at the plant less product purchases, or 29% of our plant facilities' throughput volume for the month of December 2005, was under percentage-of-proceeds agreements where we are typically responsible for the marketing of the gas and NGLs. Under these agreements, we pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

Approximately 17% of our plant facilities' gross margin, or 64% of our plant facilities' throughput volume for the month of December 2005 was under contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling or shut in production.

Approximately 2% of our plant facilities' gross margin, or 7% of our plant facilities' throughput volume for the month of December 2005 was under contracts with "keepwhole" arrangements or wellhead purchase contracts. Under "keepwhole" contracts, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The "keepwhole" component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

Powder River Basin. Our midstream operations in the Powder River Basin are fully integrated with our upstream operations as we provide the gathering, compression and treating services for our own production. Additionally we provide the same types of services for third-parties. As of December 31, 2005, our midstream assets in the Powder River Basin were primarily comprised of our coal bed methane gathering system with a capacity of 548 Mcf per day, several gas processing facilities with a combined capacity of 146 MMcf per day, and our 15% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union. We averaged 407 MMcf per day of CBM gathering volumes, including third-party gas, during the fourth quarter of 2005. Of that volume, approximately 105 MMcf per day was transported through our MIGC pipeline.

We are the construction manager and field operator of the Fort Union gathering system and header. The Fort Union system delivers coal bed methane gas to its treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. The gathering pipeline has a capacity of 635 MMcf per day. We have a long-term gathering agreement with Fort Union for 136 MMcf per day of capacity and pay demand charges on 83 MMcf per day of this capacity at $0.14 per Mcf.

We spent approximately $60.4 million in the Powder River Basin for midstream activities during 2005. Our capital budget in the Powder River Basin for midstream activities provides for expenditures of $71.1 million during 2006. Depending upon our future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin.

Greater Green River Basin. Our midstream operations in the Greater Green River Basin of southwest Wyoming are also fully integrated with our upstream operations in this area. Our midstream assets in this basin are comprised of the Granger and Lincoln Road facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous Gas Services, L.L.C., or Rendezvous, our Patrick Draw and Red Desert facilities, and our Table Rock, Wamsutter and Desert Springs gathering systems. These facilities have a combined gathering capacity of 604 MMcf per day, and in the year ended December 31, 2005, these facilities averaged throughput of 630 MMcf per day. Additionally, these systems have a combined processing capacity of 450 MMcf per day and, in the year ended December 31, 2005, processed an average of 336 MMcf per day. These capacity and processing volumes do not include volumes committed to our straddle facility described below.

In December 2004, a 200 MMcf per day processing facility adjacent to the Granger Complex was placed into service. This facility straddles a third-party regulated pipeline and processes its gas to meet pipeline specifications. The facility's capacity is contractually committed to this service, and the contract for processing this gas requires a monthly demand charge to be paid by the pipeline regardless of the amount of gas processed. These demand fees total approximately $2.2 million per year and the contract has a remaining term of nine years.

In February 2005, we completed the acquisition of several natural gas gathering and processing assets in the eastern Greater Green River Basin for approximately $28.3 million. The acquisition included the Patrick Draw processing plant with 150 MMcf per day of capacity and approximately 140 miles of related gathering systems. At December 31, 2005, Patrick Draw was processing approximately 93 MMcf per day of gas. In the third quarter of 2005, our Red Desert, Patrick Draw, Wamsutter and Desert Springs facilities, or the Red Desert Complex, were consolidated in order to reduce operating expenses and improve NGL recoveries.

We also own a 50% interest in the Rendezvous system and serve as its field operator. Rendezvous gathers gas along the Pinedale Anticline for blending or processing at either our Granger Complex or at the third-party owned and operated Blacks Fork processing facility. At December 31, 2005, the

capacity of Rendezvous was 325 MMcf per day, and the facility gathered an average of 369 MMcf per day in 2005.

Excluding the February 2005 acquisition, during 2005, we spent approximately $28.3 million in capital expenditures for midstream activities in the Greater Green River Basin. Our 2006 capital budget for midstream activities in this basin provides for expenditures of $47.8 million. This capital budget includes $47.0 million for gathering lines and installation of compression to expand the capacity of our Granger Complex, our Patrick Draw facility, our Wamsutter gathering system and our Red Desert facility and $800,000 for additional contributions to Rendezvous for the expansion of its systems.

West Texas. Our primary assets in West Texas are the Midkiff/Benedum Complex and the Gomez and Mitchell Puckett treating facilities. These facilities process gas produced by third-parties in the Permian Basin, have a combined operational capacity of 565 MMcf per day and processed an average of 261 MMcf per day in the year ended December 31, 2005. Also for this period, these facilities produced an average of 190 MMcf per day of natural gas for delivery to sales markets and produced an average of 846 MGal per day of NGLs. In 2005, our capital expenditures in this area totaled approximately $15.9 million. Our capital budget in this area provides for expenditures of approximately $18.9 million during 2006.

Oklahoma. Our primary assets in Oklahoma are the Chaney Dell and Westana systems. These facilities gather and process gas produced by third-parties in the Anadarko Basin and have a combined gas throughput capacity of 187 MMcf per day. During the year ended December 31, 2005, these facilities gathered an average of 205 MMcf per day, produced an average of 181 MMcf per day of natural gas for delivery to sales markets and produced an average of 304 MGal per day of NGLs. During 2005, our capital expenditures in this area totaled $54.5 million, including the purchase of a cyrogenic facility that is expected to be installed and operational in the second quarter of 2006. This facility provides processing capacity of 200 MMcf per day, allowing us to benefit from the increased drilling of the producers behind these facilities and the opportunity to consolidate less efficient processing capacity. Our capital budget in this area provides for expenditures of approximately $45.3 million during 2006. This budget includes $11.9 million to install the new cryogenic facility.

San Juan. Our midstream assets in the San Juan Basin of New Mexico are the San Juan River processing facility and the Four Corners Gathering system. These facilities gather and process gas produced by us and third parties in the San Juan and Paradox Basins and have a combined operational capacity of 75 MMcf per day. In 2005, these facilities gathered and processed an average of 29 MMcf per day, produced an average of 23 MMcf per day of natural gas for delivery to sales markets and produced 52 MGal per day of NGLs. During 2005, our capital expenditures in this area totaled $4.8 million. Our capital budget in this area provides for expenditures of $1.8 million during 2006.

Principal Gathering, Processing and Treating Facilities Table. The following table provides information concerning our principal gathering, processing and treating facilities at December 31, 2005.

We routinely review the economic performance of each of our operating facilities to ensure that a satisfactory rate of return is achieved. If an operating facility is not generating targeted returns we will explore various options, such as consolidation with other Western-owned or third-party-owned facilities, dismantlement, asset trades or sale. A description of the significant midstream acquisitions and dispositions since January 1, 2001, involving assets other than those that were previously discussed are:

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

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

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

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

We own and operate MIGC, Inc., an interstate pipeline located in the Powder River Basin, and MGTC, Inc., an intrastate pipeline located in northeast Wyoming. MIGC charges a Federal Energy Regulatory Commission, or FERC, approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC. MIGC earns fees on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity, whether or not the capacity is used, and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. Contracts with third parties for capacity on MIGC range in duration from one month to approximately five years, and the fees charged averaged $0.35 per Mcf in 2005. MGTC, a public utility, provides transportation and gas sales to various cities in Wyoming at rates that are subject to the approval of the Wyoming Public Service Commission.

The following table provides information concerning our principal transportation assets at December 31, 2005.

Gas. We market gas produced from our wells and gas processed at our plants, as well as gas purchased from third-parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. In addition to our offices in Denver, we have marketing offices in Houston, Texas and Calgary, Alberta. Third-party sales, firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

One of the primary goals of our gas marketing operations continues to be the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and through the use of firm transportation capacity. Historically, the gas produced in the Rocky Mountain region has traded at a substantial discount as compared to the Mid-Continent and West Coast areas, as a result of limited pipeline capacity from the region. We have historically used our firm pipeline transportation capacity to access higher priced Mid-Continent markets for both our equity production and for gas purchased from third-parties in the Rocky Mountain region.

During 2003, additional pipeline capacity out of the Rocky Mountain region went into service. This expansion contributed to a reduction in the price difference between the Rocky Mountain region and Mid-Continent market center. The additional pipeline capacity from the Rocky Mountain region to the Mid-Continent producing region of the country along with increased exploration and production in the Mid-Continent region may increase overall utilization of the pipeline systems that are used to move gas out of the Mid-Continent region to points in the Chicago area, Michigan, Ohio and the lower Mississippi River Valley. Increased throughput on those systems may cause the market price for natural gas within the Mid-Continent to be reduced relative to other markets. Consistent with our goal to preserve and enhance the value of natural gas sales, at the end of 2005, we hold approximately 98,000 MMBtu per day of firm transportation capacity out of the Mid-Continent region to market areas in the upper Midwest and the Mississippi River Valley. At mid-year 2006, we will add an additional 25,000 MMBtu per day of firm transportation capacity out of the same area.

For the year ended December 31, 2005, our total gas sales volumes averaged 1.2 Bcf per day, of which 477 MMcf per day was produced at our plants or from our producing properties. We do not expect our average daily sales volume to increase in 2006. The marketing of gas purchased from third-parties typically results in low profit margins relative to the sales price. We sell gas under agreements

with varying terms and conditions in order to match seasonal and other changes in demand. As of December 31, 2005, the weighted average duration of our sales contracts was 11 months. During the year ended December 31, 2005, we sold gas to approximately 224 end-users, pipelines, LDCs and other customers. No single customer accounted for more than approximately 13% of our consolidated revenues from the sale of gas, or 10% of total consolidated revenue, for the year ended December 31, 2005. We continually monitor and review our credit exposure to our gas marketing counterparties.

NGLs. We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third-parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast and Mid-Continent areas, which are the largest NGL markets 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, 2005, NGL sales averaged 1,862 MGal per day, of which 1,608 MGal per day was produced at our plants.

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 and clothing products. Further, consumers use propane for home heating, transportation and agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

We sell NGLs under agreements with varying terms and conditions in order to match seasonal and other changes in demand. At December 31, 2005, the terms of our sales contracts ranged from one month to three years. The marketing of NGLs purchased from third-parties typically results in low profit margins relative to the sales price. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counterparties.

In 2005, one customer accounted for approximately 23% of our consolidated revenues from the sale of NGLs, or 3% of total consolidated revenue. This customer is a large integrated energy company. We also derive revenues from contractual marketing fees charged to some producers for NGL marketing services. For the year ended December 31, 2005, these fees were less than 2% of our total consolidated revenue.

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

Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the acquisition of the gathering and processing facilities acquired in February 2005, we performed phase one environmental assessments and, where conditions warranted, performed phase two assessments. These assessments enabled us to satisfy ourselves that the disclosures by the seller were materially accurate and also to form our own risk assessment of potential environmental issues. In relation to the assets purchased in the February 2005 acquisition, one of the sites was the subject of an Administrative Order between the former owner, the State of Wyoming, and a third party who has contracted to remediate the site in accordance with the Administrative Order. As a result of the acquisition, we also became a party to the Administrative Order. Both that site and another site are insured under an insurance policy that was put in place by the seller for the costs of all remediation activities. The obligation to perform and complete those remediation activities has been assigned contractually to a third party environmental specialist whose costs will be reimbursed by the insurance policy.

We are in the process of voluntarily cleaning up substances at several of the facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have been consistent with industry practice and have not been significant in relation to our results of operations and totaled approximately $329,000 for the year ended December 31, 2005. In addition, in 2005, we paid approximately $144,000 in air emissions fees to the states in which we operate.

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

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

As a producer, processor and marketer of natural gas, we depend upon the transportation and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of our own gas supplies as well as those we process and/or market for others. Both the interstate pipelines' performance of transportation and storage services, and the rates charged for such services, are subject to the jurisdiction of the FERC, under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. At times, other system users can pre-empt the availability of interstate transportation and storage services necessary to enable us to make deliveries and/or sales of gas in

accordance with FERC-approved methods for allocating the system capacity of open access pipelines. Moreover, the rates the pipelines charge for such services are often subject to negotiation between shippers and the pipelines within FERC-established parameters, and will periodically vary depending upon individual system usage and other factors. An inability to obtain transportation and/or storage services at competitive rates can hinder our processing and marketing operations and/or adversely affect our sales margins.

Generally, neither the FERC nor any state agency regulates gathering and processing prices. The Oklahoma Corporation Commission has limited authority in some circumstances, after the filing of a complaint by a producer, to compel a gas gatherer to provide open access gathering and to set aside unduly discriminatory gathering fees. From time to time, state legislatures have considered adopting legislation that would expand the authority of the relevant state administrative body to compel a gas gatherer to publish rates, terms and conditions of its service and under some circumstances, to justify those charges. The Department of Transportation is also evaluating the regulation of gathering assets for safety reasons. We cannot predict what additional legislation or regulations the states or other federal agencies may adopt in the future regarding gas gathering.

Many of our ongoing operations are also subject to rules and regulations promulgated by various governmental authorities such as the Occupational Safety and Health Administration, or OSHA. Among other things, OSHA requires annual training on a variety of safety topics and we complete training and retain evidence of the training for each of our operating employees as required.

At December 31, 2005, we employed 800 full-time employees, of which 470 were employed at field locations. None of our employees is a union member. We consider relations with our employees to be excellent.

Volatile product prices could have a material adverse effect on our financial condition and results of operations and cash flows.

Our future financial condition and results of operations and cash flows will depend significantly upon the prices received for our natural gas and natural gas liquids, or NGLs. Prices for natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These factors include the level of domestic production, the availability of imported oil and gas, actions taken by foreign oil and gas producing nations, the availability of transportation systems with adequate capacity, the availability of competitive fuels, fluctuating and seasonal demand for oil, gas and NGLs, conservation efforts and the extent of governmental regulation of production and the overall economic environment. A substantial or extended decline in gas and/or NGL prices would depress the levels of exploration, development, production, gathering, processing and treating, transportation and marketing activities. Lower levels of these activities could result in a corresponding further decline in the demand for our natural gas and NGLs and our services and products, which could have a material adverse effect on our financial condition and results of operations and our access to capital.

The business of exploring for, developing or acquiring reserves is capital intensive. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of reserves will be impaired.

Competition for oil field services, including the availability of drilling rigs, could affect future drilling plans and costs. Future increases in the costs of conducting exploration and development may not be fully offset by increases in the prices received for natural gas or oil.

During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production. However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the drilling schedules of the operators of our non-operated properties, the issuance of drilling and water disposal permits, the availability of oil field services, the length of time for wells in the Powder River Basin to be dewatered, and the rate of normal production declines none of which is within our control. A significant reduction in the level of our production or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, there can be no assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

Our exploration and development activities are subject to federal, state and local environmental laws and regulations, and require permits from several federal, state and local agencies. In the past we have been successful in receiving the drilling and water discharge permits necessary to conduct our drilling program. There is, however, no assurance as to the future timing of the receipt of drilling and water discharge permits, any changes in regulations governing drilling and water discharge, restrictions placed on water discharge and/or quality by Wyoming or other states. Failure or delays in obtaining permits in a timely manner from the regulatory agencies and various state agencies could diminish our drilling program and hamper efforts to develop our reserves.

In addition, from time to time, various environmental groups file actions against the governmental agencies, disputing the validity of their actions in issuing permits. In the event of any adverse rulings or settlements, the governmental agencies may be required to perform further environmental analysis in affected areas and, in addition, could be ordered to cease issuing drilling permits until it has completed such further analysis. In such case, our ability to receive permits and develop our leases may be delayed or restricted.

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 such 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 discounted net cash flows prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of

those reserves are based upon assumptions about production levels, prices and costs, which may not be correct. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated.

The uncertainties of gas supply may affect our ability to replace reserves connected to our facilities.

Numerous risks affect our continued ability to replace reserves connected to our facilities. We must continually connect new wells to our gathering systems in order to maintain or increase throughput levels to offset natural declines in production volumes. In general, the volume of production from a property declines as reserves are depleted. Historically, while individual plants have experienced declines in connected reserves over time, we have been successful in connecting additional reserves to more than offset the natural declines in reserves connected to existing facilities. Successful exploration and drilling activities are necessary to maintain the level of connected reserves. However, the overall level of drilling associated with our plant facilities will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies and the pace at which drilling permits are received, none of which is within our control. There is no assurance that we will continue to be successful in replacing the volumes of dedicated reserves processed at our facilities. In addition, any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third parties. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A significant reduction in any of these activities could have a material adverse effect on our financial condition, results of operations and cash flows.

The estimated future natural gas production connected to our gathering, processing and treating facilities is based on an internal review of historical facility throughput gas volume, our interpretation of expected declines from existing connections, and assumptions that there are no new well connections to our facilities. Our assumptions in making such estimations may not be correct. In addition, 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 include our proprietary data.

Our operations are subject to environmental laws and regulations that could affect our financial position or results of operations.

Our exploration and development activities and the construction and operation of our gathering systems, plants and other facilities used for the gathering, transporting, processing, treating or storing of natural 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 environmental regulatory requirements relate to water and air pollution control or waste management. Environmental regulation can increase the cost of planning, designing, constructing and operating our facilities or well sites. We anticipate that the trend in environmental legislation and regulation will continue to be toward stricter standards. The costs for compliance with current environmental laws and regulations have not had and, we believe, will not have a material adverse effect on our financial position or results of operations. We however cannot predict the extent or timing of future regulations or legislation and whether any such regulations or legislation will have a material adverse effect on the financial results of our operations, financial position or cash flows.

The natural gas and NGL business involves certain operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other hazards and risks. These hazards could cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility. We maintain physical damage, comprehensive general liability, workers' compensation and business interruption insurance. Such insurance is subject to deductibles that we consider reasonable. However, while we are not fully insured against all risks in our business, we believe that the coverage we maintain is adequate and consistent with other companies in the industry. Consistent with insurance coverage typically available to the natural gas industry, our insurance policies do not provide coverage for losses or liabilities relating to pollution, except for sudden and accidental occurrences. If a significant event occurs that is not fully insured, it could adversely affect our operations or our results of operations, cash flows and financial condition.

Financial difficulties experienced by the companies with which we maintain relationships could have a material adverse effect on our financial condition and results of operations and cash flows.

If the companies with which we maintain trading or customer relationships or with which we participate in joint ventures experience financial difficulties, we may be subject to increased exposure to credit risk. Any inability of these companies to continue their trading relationships with us or their participation in the joint ventures or to meet their capital expenditure commitments and other financial obligations to us could have a material adverse effect on our financial condition and results of operations and cash flows. In order to minimize our credit exposure, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, negotiated accelerated payment terms with several customers, curtailed sales to certain counterparties, and increased the amount of credit which we make available to substantial companies which meet our credit requirements. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of the customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged nor whether the outcome of any challenge would be favorable to us.

Access to FERC regulated pipelines may impact our delivery and sale of gas.

As a producer, processor and marketer of natural gas and NGLs, 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 performance of transportation and storage services by interstate pipelines and the rates charged for such services are subject to the jurisdiction of the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. At times, other system users can pre-empt the availability of interstate transportation and storage services necessary to enable us to make deliveries and/or sales of gas in accordance with FERC-approved methods for allocating the system capacity of open access pipelines. Moreover, the rates the pipelines charge for such services are often subject to negotiation between shippers and the pipelines within FERC-established parameters and will periodically vary depending upon individual system usage and other factors. An inability to obtain transportation and/or storage services at competitive rates can hinder our producing, 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 has limited authority in some circumstances, after the filing of a

complaint by a producer, to compel a gas gatherer to provide open access gathering and to set aside unduly discriminatory gathering fees. From time to time, state legislatures have considered, and may do so in the future, adopting legislation that would expand the authority of the relevant state administrative body to compel a gas gatherer to publish rates, terms and conditions of its service and under some circumstances, to justify those charges. We cannot predict what additional legislation or regulations the states may adopt in the future regarding gas gathering.

In addition, we can make no assurance as to the regulations passed by FERC from time to time or the effect such regulations may have on our operating costs of MIGC, Inc., an interstate pipeline located in the Powder River Basin in Wyoming that we own and operate.

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.

There can be no assurance that the laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency, will not be changed, applied or interpreted in a manner which will have a significant impact on our overall operations.

Opportunities for expansion and availability of related financing are uncertain.

In order for us to expand our business through either the purchase or construction of new gathering and processing facilities or new exploration and development opportunities, we will be required to identify expansion opportunities and to finance such activities, using cash flow, equity or debt financing or a combination thereof. No assurance can be given that appropriate opportunities for expansion at levels of profitability that satisfies our target rates can be obtained or that financing on terms acceptable to us can be obtained. Natural gas and oil price volatility make it difficult to estimate the value of acquisitions and to budget and forecast the return on our projects. In addition, unusually volatile prices often disrupt the acquisition and divestiture market for gas and oil properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties. As a result, we may be limited in our ability to expand our business.

The natural gas exploration, production, distribution and marketing businesses are highly competitive, and there can be no assurance that we can compete successfully with other companies in the industry.

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. 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, brokers, marketers and distributors of various sizes, financial resources and experience. For marketing customers that have the capability of using alternative fuels, such as oil and coal, we also compete based primarily on price and availability of such alternative fuels. Our competitors for obtaining leaseholds and acquiring production or new exploration and development prospects include major and large independent oil companies as well as smaller independent oil companies and brokers. Competition for sales customers is primarily based upon reliability and price of deliverable natural gas and NGLs. Suppliers in our gas marketing transactions may request additional security such as letters of credit that are not required of certain of our competitors. If additional security is required, our marketing margins and volumes may be adversely impacted. There can be no assurance that we can compete successfully with other companies in the industry.

Litigation following the investigation into gas index price reporting could have a material adverse effect on us.

In 2003, we learned that several employees in our marketing department furnished inaccurate information regarding natural gas transactions to energy publications that compile and report energy index prices. We discovered the inaccuracies during a review of our marketing activities, which was being conducted in response to a subpoena issued by the CFTC. These employees identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. We have discontinued the practice of reporting pricing information to industry publications. In conjunction with our investigation into this matter, we have taken appropriate disciplinary actions including the release of one manager in our marketing department. In July 2004, we reached a settlement of this matter with the CFTC. In conjunction with this settlement, we paid a civil penalty of $7.0 million.

In 2004, we were named as a defendant in Gracey et al. v. Western Gas Resources, Inc. et al., United States District Court, Southern District of New York, Case No. 03-CV-6186 (vm) (S.D.N.Y.). The plaintiffs, traders of natural gas futures contracts on NYMEX, filed this action on behalf of themselves and a putative class of others similarly situated. In the complaint, the plaintiffs claimed that we manipulated the prices of natural gas futures on the NYMEX in violation of the Commodity Exchange Act, or CEA, by reporting allegedly "inaccurate, misleading and false trading information" to trade publications that compile and publish indices of natural gas spot prices. In addition, the complaint asserted that we aided and abetted the alleged CEA violations of others. In 2005, we reached a settlement of this matter with the plaintiffs. In conjunction with this settlement, we paid $5.9 million, or $3.8 million after-tax.

In 2005, we were also named as a defendant in J.P. Morgan Trust Company, National Association, in its Capacity as Trustee of the FI Liquidating Trust v. Oneok Inc. et al., United States District Court, for the District of Kansas, Case No. 05-2389C and Learjet, Inc., Cross Oil Refining & Marketing, Inc. Topeka Unified School District 501, on Behalf of Themselves and All Other Similarly Situated Direct Purchasers of Natural Gas in the State of Kansas v. Oneok, Inc. et al, In the District Court of Wyandotte County, Kansas, Civil Action No. 05-CV-1500. These cases are similar to the previously discussed cases and are more fully described in Note 8 to the Consolidated Financial Statements. While we believe these claims are without merit and intend to vigorously contest the allegations in these cases, we can provide no assurance as to the ultimate outcome of these cases or if future claims will be asserted against us.

Our ability to pay fixed charges and common stock dividends depends on many factors.

Our financial and operational performance depends in part on prevailing economic conditions and on various financial, business and other factors beyond our control. We cannot ensure that our cash flows and capital resources will be sufficient to pay our fixed charges, including interest expense and our cash dividends on our common stock.

Due to drilling, commodity pricing, regulatory uncertainties, including changes to existing air quality, water quality, and/or surface use regulations, and other uncertainties that are beyond our control, we can make no assurance that our capital budget for 2006 will not change or that we will actually incur our anticipated level of capital expenditure.

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, 2005.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of March 8, 2006, there were 75,450,065 shares of common stock outstanding held by 179 holders of record. The common stock is traded on the New York Stock Exchange, or NYSE, under the symbol "WGR". The following table sets forth quarterly high and low per share sales prices as reported by the NYSE Composite Tape for the quarterly periods indicated.

2005	High
Fourth Quarter	$	52.50	$	40.70
Third Quarter		52.81		35.05
Second Quarter		37.57		29.18
First Quarter		39.05		26.79

2004	High
Fourth Quarter	$	31.50	$	26.38
Third Quarter		35.25		27.50
Second Quarter		32.78		24.97
First Quarter		25.75		22.75

Declarations of dividends on our common stock are within the discretion of the board of directors. In addition, our ability to pay dividends on our common stock is restricted by covenants in our financing facilities. During each of the quarters of 2005 and 2004, we paid dividends on our common stock as indicated in the following table (amounts presented are per share amounts).

	2005
First quarter	$	0.05	$	0.025
Second quarter	$	0.05	$	0.05
Third quarter	$	0.05	$	0.05
Fourth quarter	$	0.075	$	0.05

Our board of directors has declared a dividend of $0.075 per share of common stock for the quarter ending March 31, 2006 to holders of record as of that date.

The following table summarizes our equity compensation plans under which securities may be issued as of December 31, 2005. The only types of equity compensation plans that we have are plans

that authorize the granting of options to purchase shares of our common stock and the granting of shares of our common stock subject to certain restrictions.

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

1999 Non-Employee Directors Stock Option Plan. Effective March 1999, our board of directors adopted a stock option plan that authorized the granting of options to purchase 30,000 shares of our common stock to non-employee directors. During 1999, the board of directors approved grants of options covering a total of 30,000 shares of our common stock to several board members. The exercise price of the stock underlying each option was the average closing price for the ten days prior to the grant. Under this plan, options covering up to 33¹/3% of the underlying shares are exercisable on each anniversary from the date of grant and the director must exercise the option within five years of the date each option vests. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.

Chief Executive Officer and President's Plan. Pursuant to the employment agreement, dated October 15, 2001, and the stock option agreement, dated as of November 1, 2001, between Western and Peter A. Dea, our CEO and President, we granted non-qualified stock options to Mr. Dea for the purchase of 600,000 shares of our common stock. The exercise price of the options was equal to $2.50 below the closing price per share on the effective date of his employment agreement. The stock options are subject to the conditions of the agreements and vest equally over four years and must be exercised within five years of the date on which they vest. The difference between the closing price on the effective date and the exercise price was amortized over four years as compensation expense. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full. On August 1, 2005, we entered into a new employment agreement with Mr. Dea, which due to recent changes in the tax laws required that he exercise, on or before March 15, 2006, 150,000 of the options to purchase shares of our common stock, which vested on November 15, 2005. Otherwise, per this agreement, these options will expire if not exercised.

The following table sets forth selected consolidated historical financial and operating data for Western. The data for the three years ended December 31, 2005, 2004 and 2003 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 year ended December 31, 2002 and 2001 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." Amounts in thousands, except per share amounts and operating data.

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, 2005, 2004 and 2003. This information should be read in conjunction with our Consolidated Financial Statements and related Notes thereto and the Selected Financial Data included in Item 8 of the Form 10-K. Herein we make forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including, but not limited to, those presented under "Cautionary Statement Regarding Forward-Looking Information" on page 40.

Business Strategy. Maximizing the value of our existing core assets is the focal point of our business strategy. Our core assets are our fully integrated upstream and midstream assets in the Powder River and Greater Green River Basins in Wyoming, the San Juan Basin in New Mexico, the Sand

Wash Basin in Colorado and our midstream operations in West Texas and Oklahoma. Our long-term business plan is to increase stockholder value by: (i) doubling proved natural gas reserves and equity production of natural gas from the levels achieved in 2001 over a five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

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

Exploration and Production. We explore for, develop and produce natural gas reserves independently in order to enhance and support our existing gathering and processing operations. Our producing properties are primarily located in the Powder River, Greater Green River, San Juan, and the Sand Wash Basins. These plays are relatively low-risk, multi-year development projects. These provide us with the opportunity to steadily increase our production volume over time at reasonable operating and low finding and development costs. In 2005, our average production sold was 174 MMcfe per day, which was a 13.7% increase over the average production volume sold in 2004.

We continue to seek to add additional upstream core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of unconventional gas reservoirs including tight-gas sands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitions of additional leaseholds, proved and undeveloped reserves or companies with operations primarily focused on unconventional gas developments. In January 2005, we opened an exploration and production office in Calgary, Alberta, Canada to evaluate opportunities in the Western Canadian Sedimentary Basin. Through December 31, 2005, we have acquired the drilling rights on approximately 1.0 million net acres in other unconventional gas areas and continue to expand our leasehold positions.

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

This segment of our operations has provided a stream of operating profit that is available for reinvestment into other projects or other segments of our business. Overall throughput in our facilities during 2005 remained relatively constant as compared to 2004 and averaged a total of 1.42 Bcf per day.

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

Marketing. Our gas marketing segment is an outgrowth of our gas processing and upstream activities and ensures continual flow of our produced products. One of the primary goals of our gas marketing operations is the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and NGLs and through the use of firm transportation capacity. Historically, the gas produced in the Rocky Mountain region has traded at a substantial discount as compared to the Mid-Continent and West Coast areas, as a result of limited pipeline capacity from the region. We have historically used our firm pipeline transportation capacity to access higher priced Mid-Continent and markets further east for both our equity production and for gas purchased from third-parties in the Rocky Mountain region.

We also buy and sell natural gas and NGLs in the wholesale market in the United States and Canada. These third-party sales, our firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

Year ended December 31, 2005 as compared to year ended December 31, 2004
(amounts in thousands, except per share amounts and operating data)

Net income increased $79.7 million for the year ended December 31, 2005 as compared to 2004. This increase was primarily attributable to higher production of equity gas volumes and higher commodity prices. In 2005, we incurred an after-tax charge of $3.8 million recorded in connection with a settlement of litigation. The 2004 period included an after-tax charge associated with a settlement with the Commodity Futures Trading Commission, or CFTC, of $7.0 million, and an after-tax charge associated with the early extinguishment of long-term debt of $6.7 million. Partially offsetting these items in the 2004 period was the cumulative effect of a change in accounting principle. Effective as of January 1, 2004, we revised our depreciation and depletion methodology for our oil and gas properties. This change in accounting principle resulted in a cumulative reduction of depreciation for periods prior to 2004 of $4.7 million, net of tax, in 2004.

Revenues from the sale of gas increased $682.6 million to $3,200.9 million for the year ended December 31, 2005 as compared to 2004. This increase was primarily due to a significant increase in product prices, which more than offset a decrease in sales volume of third-party product in 2005, compared to 2004. Average gas prices realized by us increased $1.87 per Mcf to $7.46 per Mcf in 2005 as compared to 2004. Included in the realized gas price were approximately $7.4 million of losses recognized in 2005 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately 75% of our equity gas for 2006 and to a lesser extent in 2007. See further discussion in "Item 7. Quantitative and Qualitative Disclosures About Market Risk." Average gas sales volumes decreased slightly to 1,171 MMcf per day for 2005 as compared to 2004.

Revenues from the sale of NGLs increased approximately $204.1 million to $654.8 million for 2005 as compared to 2004. This is primarily due to a significant increase in product prices and, to a lesser extent, an increase in sales volumes. Average NGL prices realized by us increased $0.21 per gallon to $0.96 per gallon for 2005 as compared to 2004. Included in the realized NGL price were approximately $9.2 million of losses recognized in 2005 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately 75% of our equity propane production for 2006. See further discussion in "Item 7. Quantitative and Qualitative Disclosures About Market Risk." Average NGL sales volumes increased 221 MGal per day to 1,862 MGal per day for 2005 as compared to 2004. This increase is due to the acquisition of several facilities in February 2005.

Price risk management activities changed from $20.1 million for 2004 to ($9.4) million for 2005. This change was due to the non-cash mark to market valuation of our risk management activities. This account is primarily impacted by the increase in the price of natural gas in 2005 as compared to 2004.

Product purchases increased by $669.4 million for 2005 as compared to 2004. This increase in product purchases was the result of higher product prices. On a consolidated basis, combined product purchases as a percentage of sales of all products was 83% in 2005 as compared to 86% in 2004. The reduction in this percentage is primarily the result of an increase in revenues from the sale of equity production.

Plant and transportation operating expense increased by $19.7 million for 2005 as compared to 2004. The increase for 2005 as compared to 2004 was substantially due to increased fees paid for the use of third party gathering systems behind our facilities, property tax, labor and repairs and maintenance expenses and the October 2004 and February 2005 asset acquisitions.

Oil and gas exploration and production costs increased by $36.0 million for 2005 as compared to 2004. The increase was substantially due to increased lease operating expenses, or LOE, in the Powder River Basin coal bed development and expenses associated with the San Juan properties acquired in October 2004. Overall, LOE averaged $0.82 per Mcf for 2005 and LOE in the Powder River Basin coal bed development averaged $0.91 per Mcf in 2005. In the Powder River Basin, this represents an increase of $0.12 per Mcf as compared to 2004. The increase in LOE per Mcf in the Powder River Basin is substantially due to higher water handling charges on dewatering wells in several new pilot areas that have no offsetting gas production as yet, contract labor, and fuel and operating costs of wellhead blowers in the Powder River Basin as well as increased costs related to initiating operations of the San Juan Basin production assets acquired in October 2004. We anticipate upward pressure on LOE in 2006 due to increased labor and supply costs as well as increased use of water treatment facilities.

Depreciation, depletion and amortization, or DD&A, increased by $33.2 million for 2005 as compared to 2004. For 2005 as compared to 2004, we had a $8.1 million increase in DD&A in our midstream operations primarily due to our expanding CBM gathering system in the Powder River Basin and the October 2004 and February 2005 acquisitions of additional midstream assets, and a $24.7 million increase in DD&A in our upstream operations primarily due to our continued development in the Powder River Basin, downward revisions to reserves in the Powder River Basin

based on the December 2004 reserve report, and our October 2004 acquisition of producing properties in the San Juan Basin.

Selling and administrative expenses increased by $7.9 million for 2005 as compared to 2004. This increase was primarily the result of increased administrative salaries and benefits, insurance, audit expenses, donations to the hurricane relief efforts, bad debt expense, and compensation expense related to our restricted stock plan. Additionally, 2005 included a charge of $5.9 million in connection with a settlement of litigation and 2004 included a $7.0 million charge for a settlement with the CFTC.

The Total provision for income taxes, as a percentage of Income before taxes was approximately 35.7% during 2005 as compared to 37.5% in 2004. The decrease in the percentage of income taxes is primarily due to the civil penalty paid to the CFTC in 2004, which was non-deductible for tax purposes and the effect of state taxes.

Cash flows from operating activities increased by $186.9 million in 2005 as compared to 2004. This increase was primarily due to the increase in net income and the timing of collection of accounts receivables and payment of trade accounts payable.

Cash flows used in investing activities increased by $146.0 million in 2005 as compared to 2004. This increase was primarily due to an increased level of capital expenditures including the February 2005 acquisition of additional midstream assets in the Greater Green River Basin.

Cash flows provided by financing activities increased by $11.6 million in 2005 as compared to 2004. This increase was due to a net increase in our long-term debt, which was used to fund our capital investments and proceeds received from the exercise of common stock options.

Year ended December 31, 2004 as compared to year ended December 31, 2003
(amounts in thousands, except per share amounts and operating data)

Net income increased $39.8 million for the year ended December 31, 2004 as compared to 2003. This increase was primarily attributable to higher product prices and mark-to-market non-cash gains from our economic hedges of future sales of gas utilizing our storage and transportation capacity. The price increases were somewhat offset by reduced operating profit from the marketing segment, and after-tax charges associated with a settlement with the CFTC, of $7.0 million and the early extinguishment of long-term debt of $6.7 million. Additionally, the 2004 results included a change in

accounting principle that resulted in a cumulative reduction of depreciation and depletion for periods prior to 2004 of $4.7 million, net of tax, and the 2003 results included a $6.7 million after-tax loss from the Cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003.

Revenues from the sale of gas increased $54.5 million to $2,518.3 million for the year ended December 31, 2004 as compared to the year ended December 31, 2003. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in 2004. Average gas prices realized by us increased $0.65 per Mcf to $5.59 per Mcf for the year ended December 31, 2004 as compared to 2003. Included in the realized gas price were approximately $7.4 million of gains recognized in 2004 related to futures positions on equity gas volumes. Average gas sales volumes decreased to 1,225 MMcf per day in 2004 from 1,361 MMcf per day in 2003. This decrease was the result of our reduction in third party sales volume due to the increase in product prices and related credit exposure.

Revenues from the sale of NGLs increased $104.7 million to $450.8 million for the year ended December 31, 2004 as compared to 2003. This was primarily due to a significant increase in product prices as sales volumes were relatively constant. Average NGL prices realized by us increased $0.17 per gallon to $0.75 per gallon in 2004 as compared to 2003. Included in the realized NGL price were $16.3 million of losses recognized in 2004 related to futures positions on equity NGL volumes. Average NGL sales volumes remained relatively constant in 2004 as compared to 2003.

Price risk management activities changed from ($16.4) million for the year ended December 31, 2003 to $20.1 million for the year ended December 31, 2004. This change was due to the non-cash mark to market valuation of our risk management activities. This account was primarily impacted by the increase in the price of natural gas in 2004 as compared to 2003.

Product purchases increased by $84.4 million for the year ended December 31, 2004 as compared to 2003. The increase in product purchases in 2004 as compared to 2003 was the result of an increase in product prices that more than offset the reduction in third party sales volume. Overall, combined product purchases as a percentage of sales of all products decreased to approximately 86% in 2004 from 87% in 2003. The reduction in this percentage was primarily the result of a decrease in the sale of third party product.

Plant and transportation operating expense increased by $7.5 million for the year ended December 31, 2004 as compared to 2003. The increase was primarily due to a $4.2 million increase in property tax expense, including approximately $1.8 million for prior year property taxes in Oklahoma. Also contributing to the increase was increased fuel costs and compression rental expenses.

Oil and gas exploration and production expenses increased by $25.4 million in the year ended December 31, 2004 as compared to 2003. The increase was substantially due to increased lease operating expenses, or LOE, in the Powder River Basin coal bed development. Overall, LOE averaged $0.68 per Mcf in 2004 as compared to $0.46 per Mcf in 2003. The increase in LOE is substantially due to higher water handling charges, contract labor, and fuel and operating costs of wellhead blowers in the Powder River Basin.

Depreciation, depletion and amortization, or DD&A increased by $21.6 million in the year ended December 31, 2004 as compared to 2003. The increase was the result of additional capital expenditures and depreciation and depletion on our oil and gas assets. In total, we had an $8.0 million increase in DD&A in our midstream operations primarily due to our expanding CBM gathering system in the Powder River Basin. We also had a $13.6 million increase in DD&A in our upstream operations primarily due to our continued development in the Powder River Basin, downward revisions to reserves in the Powder River Basin, and our October 2004 acquisition of producing properties in the San Juan Basin. Also contributing to the increase in DD&A in our upstream operations was a change in our

method of calculating DD&A. Effective January 1, 2004, we redefined the asset groupings for the calculation of depreciation and depletion on our oil and gas properties from a well-by-well basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin. This change resulted in an increase in DD&A of $4.9 million in 2004.

The change in the depreciation and depletion methodology is treated as a change in accounting principle. Accordingly, the Accumulated depreciation, depletion and amortization for these assets has been recalculated under the new methodology. The cumulative effect of the change in depreciation and depletion methodology was a benefit of $4.7 million, net of tax, and was presented in the Consolidated Statement of Operations under the caption Cumulative effect of change in accounting principle, net of tax.

Selling and administrative expenses increased by $11.8 million in the year ended December 31, 2004 as compared to 2003. The increase in selling and administrative expenses included a $7.0 million settlement with the CFTC in July 2004 associated with reporting price information to industry publications, and increased salary and benefit costs.

The Total provision for income taxes, as a percentage of Income before income taxes was approximately 37.5% during the year ended December 31, 2004 as compared to 37.0% in 2003. This increase was due to the settlement paid to the CFTC, which was non-deductible for tax purposes.

Cash flows from operating activities decreased by $35.1 million in the year ended December 31, 2004 as compared to 2003. This decrease was primarily due to the timing of cash receipts and payables and an increase in our inventory of products held for future resale.

Cash flows used in investing activities increased by $105.4 million in 2004 as compared to 2003. This increase was due to an increase in capital expenditures and acquisitions in 2004.

Cash flows provided by financing activities increased by $95.9 million in 2004 as compared to 2003. This increase was due to additional borrowings used to fund our capital expenditure program.

Preferred Stock Conversion/Redemption. In December 2003, we issued a notice of redemption for a total of 800,000 shares of our $2.625 cumulative convertible preferred stock. The holders of these shares had the right to convert them into shares of our common stock in lieu of receiving the redemption price in cash. In January 2004, we issued an additional 1,979,244 shares of common stock to holders who elected to convert their shares and paid $672,000 in cash proceeds to complete this redemption. In March 2004, we issued an additional notice of redemption for the remaining 1,260,000 shares of our $2.625 cumulative convertible preferred stock. In April 2004, we issued an additional 3,113,582 shares of common stock to holders who elected to convert their shares and paid $391,000 in cash proceeds to complete this redemption. After these redemptions, the $2.625 cumulative convertible preferred stock was delisted from trading on the New York Stock Exchange and was deregistered by the SEC.

Common Stock Split. On June 18, 2004, we completed a two-for-one split of our common stock, which was distributed in the form of a stock dividend. Shareholders of our common stock received one additional share for every share of common stock held on the record date of June 4, 2004. Upon completion of the stock split, we had approximately 73.6 million shares of common stock outstanding. After the stock split, each share of common stock outstanding or thereafter issued includes or will include one-half of a Series A Junior Participating Preferred Stock purchase right. We have restated our financial information to reflect this split for all periods presented.

Price Reporting to Gas Trade Publications. In 2003, we learned that several employees in our marketing department furnished inaccurate information regarding natural gas transactions to energy publications that compile and report energy index prices. We discovered the inaccuracies during a review of our marketing activities, which was being conducted in response to a subpoena issued by the CFTC. These employees identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. We have discontinued the practice of reporting pricing information to industry publications. In conjunction with our investigation into this matter, we have taken appropriate disciplinary actions including the release of one manager in our marketing department. In July 2004, we reached a settlement of this matter with the CFTC. In conjunction with this settlement, we paid a civil penalty of $7.0 million.

Acquisition of San Juan Properties. In October 2004, we acquired oil and gas assets in the San Juan Basin of New Mexico for approximately $82.2 million, plus assumed liabilities. The purchase included 32,000 gross acres, or 24,000 net acres, with approximately 100 wells that were producing an average of 15 MMcf per day, gross, or 11 MMcf per day, net, of coal bed methane. The purchase also included approximately 130 miles of related gathering systems, which are connected to our existing San Juan River plant.

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

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

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $237.6 million for the year ended December 31, 2005 as compared to $168.9 million in 2004. The increase in operating profit in this segment in 2005 was primarily due to higher realized prices and a 5% increase in throughput volume.

Exploration and Production. The Exploration and Production segment realized segment-operating profit of $253.6 million in 2005 as compared to $156.1 million in 2004. The increase was due to increased equity production, higher product prices, and the acquisition of production assets in the San Juan Basin in the fourth quarter of 2004. During 2005, our production of natural gas as compared to

2004 increased by 14% to 63.1 Bcfe. The following table sets forth the average sales price received for our oil and gas products in the years ended December 31, 2005, 2004 and 2003.

Marketing. The Marketing segment realized segment-operating profit of $25.3 million for the year ended December 31, 2005 compared to $38.1 million in 2004. The decrease in segment-operating profit was primarily due to non-cash mark-to-market losses from economic hedges of future sales of gas utilizing our storage and transportation capacity for the year ended December 31, 2005 compared to a gain for the year ended December 31, 2004. As the stored or transported natural gas is sold and the future sale derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings.

Transportation. The Transportation segment realized segment-operating profit of $12.2 million in the year ended December 31, 2005 compared to $11.0 million in 2004. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

The application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an interpretation and implementation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. For further details on our accounting policies, and the estimates, assumptions and judgments we use in applying these policies and a discussion of new accounting rules, see "Note 2 of the Notes to Consolidated Financial Statements".

Use of Estimates. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported for assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the amounts reported for revenues and expenses during the reporting period. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. However, actual results may differ significantly from the estimates used. Any effects on our business, financial position

or results of operations resulting from revisions to these estimates will be recorded in the period in which the facts that necessitate a revision become known. Although there are a number of areas where we use estimates, what we believe to be the most significant ones are discussed below.

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

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

Our reserve estimates are prepared by a third-party reservoir engineering firm and are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future rates of production and the timing of development expenditures. The accuracy of these estimates is a function of the quality of available data, and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may not be correct. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated. We estimate that a 5% change in our reserves either upward or downward would decrease or increase, respectively, our depreciation and depletion on our oil and gas assets by approximately $3.8 million and $3.4 million annually.

Asset Retirement Obligations. We use significant judgment in estimating our future liability for asset retirement. We evaluate each asset and in some cases individual components of assets to determine and estimate the future cost and timing of retiring those assets. The estimate of the future cost is then discounted back to the present and recorded as a liability. This liability will vary based upon the probability, timing and the extent of remediation necessary to reclaim those facilities, the discount factor used in those determinations and the projected costs of the remediation. We evaluate these estimates on an ongoing basis and modify our assumptions as appropriate. During 2005 and 2004, we increased our estimate of the retirement costs for our assets by $1.5 million and $7.2 million, respectively.

Impairment of Long-Lived Assets. If changes in the expected performance of an asset occur, or if overall economic conditions warrant, we will review our assets to determine their economic viability. In accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets", assets are to be evaluated at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. Accordingly, our review is completed at the plant facility, the related

group of plant facilities or the oil and gas producing field or producing coal seam level. In order to determine whether an impairment exists, after a triggering event as defined in SFAS No. 144, we compare the net book value of the asset to the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the associated reserves. If an impairment exists, write-downs of assets are based upon the fair market value of the asset usually determined by the expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. This analysis is sensitive to, among other things; management's expectation of commodity prices, operating costs, drilling plans, production rates and the evaluation in determining asset groupings for which cash flows are largely independent of the cash flows of other assets. For unevaluated oil and gas properties, we annually review our development plans and drilling history in that area to determine if an impairment of those properties is warranted. During 2005, we recognized impairments of $1.5 million on oil and gas properties. During 2004 and 2003, we had no impairments of long-lived assets.

Identification of Derivatives and Mark to Market Valuations. The determination of which contractual instruments meet the definition of a derivative under accounting rules is subject to differing interpretations as is the valuation of those derivatives. We analyze our contracts to determine whether or not they qualify as derivatives and use our judgment to determine their value. This analysis is dependent upon commodity prices, outside market factors and management's intent upon entering into these contracts. An analysis of the impact of the change in market prices on the value of our derivatives is included in "Item 7A. Quantitative and Qualitative Disclosures on Market Risk."

At December 31, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 16.1 Bcf. This inventoried gas was sold forward. Based on a $1.00 increase in the forward price of gas in the anticipated month of withdrawal, the change in the non-cash mark-to-market value of these derivatives will reduce pre-tax earnings by $16.1 million and a $1.00 decrease in the forward price of gas in the anticipated month of withdrawal will increase pre-tax earnings by $16.1 million. As the stored or transported natural gas is sold and the future sale derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings and Net cash from operating activities.

As of March 8, 2006, we sold basis swaps for 102,500 MMBtu per day at various sales points for 2008, at an average differential of $1.09. These positions will minimize our price risk as it relates to the change in the basis differential from NYMEX to our various sales points. As we did not sell forward our equity natural gas in conjunction with these basis transactions, these positions are not eligible for hedge accounting treatment. Accordingly, these transactions will be marked-to-market through Price risk management activities. Based on a $0.10 increase in the forward basis differential in the anticipated month of sale, the change in the non-cash mark-to-market value of these derivatives will increase pre-tax earnings by $3.7 million and a $0.10 decrease in the forward basis differential in the anticipated month of sale will decrease pre-tax earnings by $3.7 million. As our equity gas is sold and the future basis derivatives are settled, we will realize the economic effect of these transactions through earnings and Net cash from operating activities.

Contingent Liabilities. We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes may differ from our current assumptions and

estimates and could materially affect future results of operations for any particular quarterly or annual period.

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

SFAS No. 123(R). Effective January 1, 2006, we will adopt Statement of Financial Accounting Standards No. 123 (revised 2004), "Share-Based Payment", or SFAS 123(R), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options based on estimated fair values. SFAS 123(R) supersedes our previous accounting under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees", or APB 25, for periods beginning in fiscal 2006. In March 2005, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107, or SAB 107, relating to SFAS 123(R). We will apply the provisions of SAB 107 in our adoption of SFAS 123(R).

We will adopt SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006, the first day of our fiscal year 2006. Our Consolidated Financial Statements as of and for the three months ended March 31, 2006 will reflect the impact of SFAS 123(R). In accordance with the modified prospective transition method, our Consolidated Financial Statements for prior periods will not be restated to reflect, and will not include, any impact of SFAS 123(R). Stock-based compensation expense to be recognized under SFAS 123(R) for the three months ended March 31, 2006 will be approximately $2.5 million for stock-based compensation expense related to employee stock options. There will be no stock-based compensation expense related to employee stock options during the three months ended March 31, 2005.

SFAS 123(R) requires us to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R), we accounted for stock-based awards to employees and directors using the intrinsic value method in accordance with APB 25 as allowed under Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation", or SFAS 123. Under the intrinsic value method, with the exception of the options granted under the Chief Executive Officer and President's Plan, no stock-based compensation expense had been recognized in our Consolidated Statement of Operations, because the exercise price of our stock options granted to employees and directors equaled the fair market value of the underlying stock at the date of grant.

Stock-based compensation expense to be recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense to be recognized in our Consolidated Statement of Operations for the first quarter of fiscal 2006 will include compensation expense for share-based payment awards granted prior to, but not yet vested as of January 1, 2006. This expense will be based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123. Compensation expense for the share-based payment awards granted subsequent to December 31, 2005 will be based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In conjunction with the adoption of SFAS 123(R), we will continue our method of attributing the value of stock-based compensation using the straight-line single option method. As stock-based compensation expense recognized in the Consolidated Statement of Operations for the first quarter of fiscal 2006 will be based on awards ultimately expected to vest, it will be reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In our pro forma information required under SFAS 123,

presented in Note 2 under the heading "Stock Compensation", for the periods prior to fiscal 2006, we also estimated compensation expense based on awards ultimately expected to vest.

In accordance with the adoption of SFAS 123(R), we will continue to use the Black-Scholes option pricing model, or Black-Scholes model, for the valuation of share-based awards. Our determination of fair value of share-based payment awards on the date of grant using the Black-Scholes model is affected by our stock price as well as assumptions regarding variables, including, but not limited to, our expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. In our opinion, the Black-Scholes model provides an accurate measure of the fair value of our employee stock options.

On November 10, 2005, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position No. FAS 123(R)-3, or FSP "Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards." This FSP allows us to take up to one year from the later of our initial adoption of SFAS 123(R) or the effective date of the FSP to evaluate the available transition alternatives related to the accounting for the tax effects of share-based payment awards. Accordingly, we are considering the alternatives and have not yet elected a transition method.

SFAS No. 151. SFAS No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4" was issued in November 2004 and is effective for us for inventory costs incurred in fiscal years beginning after June 15, 2005, and will be applied prospectively. SFAS No. 151 amends APB Opinion No. 43, Chapter 4, "Inventory Pricing" to clarify the accounting for abnormal amounts of costs and the allocation of fixed production overheads. We will adopt SFAS No. 151 on January 1, 2006 and believe that the adoption of this pronouncement will not affect our results of operations, financial position or cash flows.

EITF No. 04-13. At its September 2005 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty." This Issue addresses the question of when it is appropriate to measure non-monetary purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. EITF 04-13 requires that two or more exchange transactions involving inventory with the same counterparty that are entered into in contemplation of one another should be combined for the purposes of evaluating the effect of APB Opinion No. 29, "Accounting for Nonmonetary Transactions".

In order to minimize transportation costs or make product available at a location of our customer's preference, from time to time, we will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location. In accordance with EITF 04-13, these transactions will be required to be reported on a sales net of purchases basis. This EITF is effective for transactions entered into or modified after March 15, 2006. To the extent transactions are required to be netted, it will result in a reduction of revenues and costs by an equal amount, but will have no impact on net income or cash flows.

In accordance with EITF 03-11, we record revenue on these transactions on a gross basis versus sales net of purchases basis because we obtain title to the product that we buy, bear the risk of loss, credit and performance exposure on these transactions, and take physical delivery of the product. For the years ended December 31, 2005, 2004 and 2003, we have recorded revenues of $148.7 million, $92.6 million and $95.5 million, respectively, and product purchases of $140.8 million, $86.7 million and $84.2 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counter party at different locations and at market prices at those locations.

FASB Interpretation No. 47. FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143", or FIN 47, was issued in

March 2005 and is effective in fiscal periods ending after December 15, 2005. FIN 47 clarifies the term "conditional asset retirement obligation" as used in FASB Statement 143, "Accounting for Asset Retirement Obligations". Conditional asset retirement obligations as used in FASB Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. We adopted this interpretation in the fourth quarter of 2005 and the adoption did not have a material impact on our results of operation, financial position or cash flows.

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

During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production. However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the drilling schedules of the operators of our non-operated properties, the issuance of drilling and water disposal permits, the availability of oil field services, and the length of time for wells in the Powder River Basin to be dewatered, none of which is within our control. A significant reduction in the level of our production or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows.

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

significant reduction in any of these activities could have a material adverse effect on our financial condition, results of operations and cash flows.

In the third quarter of 2005, the Gulf Coast of the United States was impacted by two major hurricanes. These storms resulted in the curtailment of natural gas and oil production from the Gulf of Mexico, and the operations of major refineries and gas processing facilities in Texas, Louisiana and Mississippi. Our operations did not sustain any physical damage from these hurricanes, and our liquidity was not materially impacted as our counterparties and customers continued to make timely payments. However, in September 2005, one of our customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. At the time of the bankruptcy filing, we had an outstanding account receivable from this utility of $4.1 million. In the third quarter of 2005, we reserved $800,000 against this amount, which represents our best estimate of the current market value of this receivable.

We believe that the amounts available to be borrowed under our financing facilities, together with the net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or use a combination of these 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 expect our dividends to total approximately $22.5 million in 2006. These dividends and our $10 million of scheduled repayments of long-term debt in 2006 are expected to be funded with amounts available under the revolving credit facility.

Sources and Uses of Funds. Our sources and uses of funds for the year ended December 31, 2005 are summarized as follows (dollars in thousands):

Sources of funds:
Borrowings under our revolving credit facility		$	5,112,065
Borrowings under our master shelf agreement			25,000
Proceeds from the dispositions of property and equipment			2,860
Net cash provided by operating activities			396,097
Distributions from equity investments			2,309
Change in outstanding checks			31,360
Proceeds from exercise of common stock options			16,014

	Total sources of funds	$	5,585,705

Uses of funds:
Payments under our revolving credit facility (including debt issue costs)		$	5,055,214
Capital expenditures			451,273
Payments made under our master shelf agreement			35,000
Contributions to equity investments			2,324
Common dividends paid			15,086

	Total uses of funds	$	5,558,897

Capital Investment Program. We currently anticipate capital expenditures in 2006 of approximately $665.8 million. The 2006 capital budget is a 45% increase over the amount expended in 2005. This

increase is the result of a planned March 2006 acquisition of certain CBM properties and an expected increase in drilling activity in each of our upstream areas and additional drilling activity by third party producers whose acreage is dedicated to our midstream facilities. Overall, capital expenditures in the Powder River Basin CBM development and in the Greater Green River Basin operations represent 52% and 22%, respectively, of the total 2006 budget. This budget may be increased to provide for acquisitions if approved by our board of directors.

The 2006 capital budget and our capital expenditures during the year ended December 31, 2005 are presented in the following table (dollars in thousands).

Type of Capital Expenditure		2006 Capital Budget			Capital Expenditures During the Year Ended December 31, 2005
Gathering, processing, treating and pipeline assets		$	185.0	*	$	166.0	*
Exploration and production and lease acquisition activities			326.2			245.7
Acquisition of Greater Green River Basin midstream assets			—			28.3
Acquisition of CBM properties			136.7			—
Information technology and other items			4.5			4.0
Capitalized interest and overhead			13.4			13.3

	Total Capital Expenditures	$	665.8		$	457.3

Contractual Commitments and Cash Obligations. A summary of our contractual commitments and cash obligations as of December 31, 2005 is as follows (dollars in thousands):

Guarantee of Fort Union Project Financing. We own a 15% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator. Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming. Initial construction and subsequent expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis with the final payment due in 2009. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Operating Leases. In the ordinary course of our business operations, we enter into operating leases for office space, and for office, communication, transportation and compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. Our leases have terms ranging from one month to ten years and the majority of the equipment leases have return or fair market purchase options available at various times during the lease. If we were to exercise the purchase options on all the leased compression equipment, these purchase options would require the capital expenditure of approximately $45.0 million between 2007 and 2013.

Firm Transportation Capacity. Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. Firm transportation agreements generally require the payment of fixed monthly fees regardless of the quantity of gas that flows under a particular agreement. These agreements are not reflected on our Consolidated Balance Sheet.

At December 31, 2005, the fixed fees associated with our then existing contracts for firm transportation capacity during 2006 will average approximately $0.16 per Mcf. The associated contract periods range from one month to twelve years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

Firm Storage Capacity Agreements. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of December 31, 2005, we had contracts in place for approximately 17.0 Bcf of storage capacity at various third-party facilities. Firm storage agreements generally require the payment of fixed monthly fees regardless of the quantity of gas that is in storage under a particular agreement. Of the total storage capacity under contract, at December 31, 2005, approximately 6.5 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc., and Western guarantees the subsidiary's performance under these contracts. This subsidiary is wholly owned by us and fully consolidated in our financial statements.

The fees associated with these contracts in 2006 will average $0.68 per Mcf of annual capacity. The associated contract periods at December 31, 2005 had an average term of 32 months. At December 31, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 16.1 Bcf at an average cost of $8.29 per Mcf compared to 16.3 Bcf at an average cost of $5.61 per Mcf at December 31, 2004. These positions are for storage withdrawals within the next six months. At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product.

At December 31, 2005, we held NGLs in line pack and in storage at various third-party facilities of 3,141 MGal, consisting primarily of propane and ethane, at an average cost of $0.45 per gallon compared to 2,745 MGal at an average cost of $0.30 per gallon at December 31, 2004.

Revolving Credit Facility. At December 31, 2005, the commitment under the revolving credit facility was $700 million with a maturity date in November 2010. At December 31, 2005, $285.0 million was outstanding under this facility. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries, and these subsidiaries also guarantee the borrowings under the facility.

The borrowings under our credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio. The base rate is the agent's published prime rate. We also pay a quarterly commitment fee on undrawn amounts ranging between 0.10% and 0.30%, depending on our debt to capitalization ratio. This fee is paid on unused amounts of the commitment. As of December 31, 2005, the interest rate payable on borrowings under this facility was approximately 5.3% per year. Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0. The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company. This facility has been rated Ba1 by Moody's and BB+ by Standard and Poor's.

Master Shelf Agreement. Amounts outstanding under our master shelf agreement at December 31, 2005 are as indicated in the following table (dollars in thousands):

Our borrowings under our master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under this facility. All of

the borrowings under our master shelf agreement can be prepaid prior to their final maturity by paying a yield-maintenance fee. Under our master shelf agreement, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a quarterly test of EBITDA, as defined in our master shelf agreement, to interest for the last four quarters in excess of 3.0 to 1.0.

In December 2004, we gave notice to Prudential of our intention to prepay the $25 million note due January 17, 2008. This note bore interest at 6.36% per annum and was prepaid at par on January 18, 2005. To fund the prepayment, we issued a new $25 million note to Prudential, due January 2015 and bearing interest at 5.57% per annum. During 2006, we will make scheduled payments totaling $10.0 million on this facility. We intend to fund this repayment with funds available under the revolving credit facility.

Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the acquisition of the gathering and processing facilities acquired in February 2005, we performed phase one environmental assessments and, where conditions indicated, phase two assessments. These assessments enabled us to satisfy ourselves that the disclosures by the seller were materially accurate and also to form our own risk assessment of potential environmental issues. In relation to the assets purchased in the February 2005 acquisition, one of the sites was the subject of an Administrative Order between the former owner, the State of Wyoming and a third party who has contracted to remediate the site in accordance with the Administrative Order. As a result of the acquisition, we also became a party to the Administrative Order. Both that site and another site are insured under an insurance policy that was put in place by the seller for the costs of all remediation activities. The obligation to perform and complete those remediation activities has been assigned contractually to a third party environmental specialist whose costs will be reimbursed by the insurance policy.

The Private Securities Litigation Reform Act of 1995 ("the Act") provides a safe harbor for forward-looking information made on our behalf. All statements, other than statements of historical facts, which address activities or actions that we expect or anticipate will or may occur in the future, and growth of our operations and other such matters are forward-looking terminology, such as "may," "intend," "will," "should," "expect," "anticipate," "estimate," "plan," "predict" or "continue" or comparable terminology.

This Annual Report contains forward-looking statements relating to, without limitation, our future economic performance, plans and objectives for future operations and forecasts of revenue and other financial items. Forward-looking statements made by us are based on our knowledge of our business and the environment in which we operate, but any one, or a combination, of factors could cause actual results to differ materially from our projections in the Annual Report. These factors, set forth herein and in our other documents on file with the SEC, include our ability to expand our gathering operations, completion of our budgeted capital expenditures, the success of our drilling activities, our ability to respond to competitive pressures, the composition of gas to be treated and the drilling schedules and success of producers with acreage dedicated to our facilities, the condition of the capital markets, uncertainties associated with ongoing and future litigation and legal and regulatory programs (including those described under Items 1 and 3 of this Annual Report on Form 10-K, in our quarterly reports on Form 10-Q and in our current reports on Form 8-K, and any amendments thereto) and numerous other factors affecting our business generally and in the markets for gas and NGLs in which we participate. The forward-looking statements speak only as to the date when they are made. We assume no obligation to update and supplement forward-looking statements that become untrue because of subsequent events.

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

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

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

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

process. Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based upon the mark-to-market value of their net exposure. We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions.

We continually monitor and review the credit exposure to our marketing counterparties. In recent months the prices of natural gas and NGLs, and therefore our credit exposures, have increased significantly. Additionally, as a result of the damage in the Gulf States caused by hurricanes Katrina and Rita, prices increased even more dramatically, and several of our counterparties experienced a significant amount of damage to their operating assets. In September 2005, one of our customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. At the time of the bankruptcy filing, we had an outstanding account receivable from this utility of $4.1 million. In the third quarter of 2005, we reserved $800,000 against this amount, which represents our best estimate of the current market value of this receivable.

In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, negotiated accelerated payment terms with several customers, curtailed sales to certain counterparties, and increased the amount of credit which we make available to substantial companies which meet our credit requirements. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of the customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

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

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

Hedge Positions. Our hedge contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Sale of gas or Sale of natural gas liquids when the hedged transactions occur.

instrument hedging the transaction. We utilize crude oil as a surrogate hedge for natural gasoline and condensate. Our hedges are tested for effectiveness at inception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for this test. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During 2005, we recognized a loss of $208,000 from the ineffective portions of our hedges.

Outstanding Equity Hedge Positions and the Associated Basis for 2006 and 2007. The following table details our hedge positions as of March 8, 2006. In order to determine the hedged price to the particular operating region, deduct the basis differential from the settle price. There is no associated cost for the hedges.

Account balances related to hedging transactions (designated as cash flow hedges under SFAS 133) at December 31, 2005 were $23.4 million in Current assets from price risk management activities, $19.3 million in Current liabilities from price risk management activities, $1.5 million in Deferred income tax payable, net, and a $2.7 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Stockholders' equity. All of the unrealized gain in Accumulated other comprehensive income will be reclassified to earnings in 2006.

Value at Risk. We measure market risk in our natural gas and liquid marketing portfolios using value-at-risk, or VaR. We define VaR as a measure of the maximum expected loss over a given horizon under normal market conditions. VaR does not explicitly indicate potential realized losses. VaR does, however, implicitly indicate a firm's potential realized loss if market conditions were to remain constant or if the portfolio is liquidated within the specified time period. Our calculations are derived from Financial Engineering Association's VaR Works using the variance/co-variance method. We assume a one-day holding period with a 95% confidence level. There is a 95% (19 out of 20 business days) chance that the portfolio loss will be less than a specified amount if the entire portfolio were liquidated the next day. As of December 31, 2005, our VaR position for natural gas and liquid marketing portfolios was $500,000 and the average for all of 2005 for these portfolios was $408,000. This figure includes the risk related to our entire marketing portfolio of natural gas and NGL financial instruments and the related underlying physical transactions including stored gas volumes.

We also measure market risk by sensitivity valuations. As of December 31, 2005, an increase in natural gas prices of $1.00 per MMbtu would lead to an increase in the fair value of our marketing portfolio, including the related underlying physical transactions including stored gas volumes, of

$637,000 and an increase in crude oil prices of $5.00 per barrel would lead to an increase in the fair value of our marketing portfolio of $916,000.

Earnings Sensitivities. At December 31, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 16.1 Bcf. This inventoried gas was sold forward. Based on a $1.00 increase in the forward price of gas in the anticipated month of withdrawal, the change in the non-cash mark-to-market value of these derivatives will decrease pre-tax earnings by $16.1 million and a $1.00 decrease in the forward price of gas in the anticipated month of withdrawal will increase pre-tax earnings by $16.1 million. As the stored or transported natural gas is sold and the future sale derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings and Net cash from operating activities.

Summary of Derivative Positions. A summary of the net change in our derivative position from December 31, 2004 to December 31, 2005 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2004	$	15,640
Decrease in value due to change in price		(21,328	)
Decrease in value due to new contracts entered into during the period		(6,082	)
Losses realized during the period from existing and new contracts		31,910
Changes in fair value attributable to changes in valuation techniques		—

Fair value of contracts outstanding at December 31, 2005	$	20,140

A summary of our net outstanding derivative positions at December 31, 2005 is as follows (dollars in thousands):

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 United States 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, 2005, we had sold forward contracts for $45.7 million in Canadian dollars in exchange for $38.9 million in United States dollars, and the fair market value of these contracts was a loss of $490,000 in United States dollars.

This Annual Report on Form 10-K for the year ended December 31, 2005 includes our Consolidated Balance Sheet at December 31, 2005 and 2004; and our Consolidated Statement of Operations, Consolidated Statement of Cash Flows and Consolidated Statement of Stockholders' Equity for each of the three years in the period ended December 31, 2005, and the Notes thereto.


Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Consolidated Statement of Operations
Consolidated Statement of Changes in Stockholders' Equity
Notes to Consolidated Financial Statements
Supplementary Data
Supplemental Information on Oil and Gas Producing Activities

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment using those criteria, management concluded that, as of December 31, 2005, our internal control over financial reporting is effective.

We conduct a portion of our oil and gas operations through joint operating agreements with other companies. Under a portion of these joint operating agreements, the other company is the operator of the well and charges us a proportional share of the cost of the well and the on-going well operations. Under the agreements, we have the contractual right to audit the charges billed to us, but we do not have the contractual right or ability to dictate or modify the internal controls over financial reporting of these entities and do not have the ability, in practice, to assess those controls. Therefore, the internal controls over financial reporting at these operations have not been included in our assessment of the effectiveness of the Company's internal control over financial reporting. These oil and gas operations are owned through undivided interests and are accounted for under the proportionate consolidation method in our consolidated financial statements. These properties had total property, plant and equipment assets and total revenues of $368 million and $269 million, respectively, representing 16% and 7% of our corresponding consolidated financial statement amounts, and 57% and 66% of our corresponding Exploration and Production Segment amounts, as of and for the year ended December 31, 2005.

Management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

We have completed integrated audits of Western Gas Resources, Inc.'s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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 2 to the consolidated financial statements, the Company changed its method of computing depletion for oil and gas properties effective January 1, 2004, its method of accounting for asset retirement obligations effective January 1, 2003, and its method of testing long-lived assets for impairment in 2003.

Also, in our opinion, management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal

control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management's Report on Internal Control Over Financial Reporting, management has excluded its oil and gas operations managed by other joint interest operators from its assessment of internal control over financial reporting as of December 31, 2005 because the Company does not have the ability to dictate or modify the internal control over financial reporting of these entities and does not have the ability, in practice, to assess those controls. We have also excluded the internal controls over financial reporting at these oil and gas operations managed by other joint interest operators from our audit of internal control over financial reporting. These oil and gas operations are owned through undivided interests and are accounted for under the proportionate consolidation method in the Company's consolidated financial statements. These properties had total property, plant and equipment assets and total revenues of $368 million and $269 million, respectively, representing 16% and 7% of the corresponding consolidated financial statement amounts, as of and for the year ended December 31, 2005.

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.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except 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 of the United States and Canada. 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 and Southwestern regions of the United States.

In 2002, the Company adopted a Stockholder Rights Plan under which Series A Junior Participating Preferred Stock Purchase Rights were distributed as a dividend at the rate of one-half of one right for each share of its common stock held by stockholders of record as of the close of business on April 9, 2002. Each right entitles the Stockholder, subject to adjustment, 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.

In June 2004, the Company completed a two-for-one split of its common stock, which was distributed in the form of a stock dividend. Stockholders of the Company's common stock received one additional share for every share of common stock held on the record date of June 4, 2004. After the stock split, each share of common stock outstanding or thereafter issued includes or will include one-half of a Series A Junior Participating Preferred Stock purchase right. The Company has restated its financial information to reflect this split for all periods presented.

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 per share conversion price of $19.88. In November 2003 and in December 2003, the Company issued notices of redemption for approximately 700,000 and 800,000 shares, respectively, of its $2.625 cumulative convertible preferred stock at the liquidation preference plus 0.525% premium. In relation to the notice of redemption issued in November 2003, in December 2003 a total of 1,701,400 common shares were issued and $1.2 million was paid in cash to complete the redemption. In relation to the notice of redemption issued in December 2003, in January 2004 a total of 1,979,244 common shares were issued and $672,000 was paid in cash. In March 2004, the Company issued an additional notice of redemption for the remaining 1,260,000 shares of its $2.625 cumulative convertible preferred stock. In April 2004, the Company issued an additional 3,113,582 shares of common stock to holders who elected to convert their shares and paid $391,000 in cash proceeds to complete this redemption. After these redemptions, the $2.625 cumulative convertible preferred stock was delisted from trading on the New York Stock Exchange and was deregistered by the Securities and Exchange Commission.

Acquisition of San Juan Properties. In October 2004, the Company acquired oil and gas assets in the San Juan Basin of New Mexico for approximately $82.2 million, plus assumed liabilities. The

purchase also included related gathering systems, which are connected to the Company's San Juan River plant. In connection with this acquisition, the Company increased Oil and gas properties and equipment by $72.6 million and increased Gas gathering, processing and transportation by $13.3 million.

Acquisition and Disposition of Gathering Systems. In February 2005, the Company acquired certain natural gas gathering and processing assets in the eastern Greater Green River Basin for approximately $28.3 million.

In February 2003, the Company acquired several gathering systems in Wyoming, primarily located in the Greater Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River did not integrate directly into the Company's existing systems, and accordingly these systems were sold in 2003. During the year ended December 31, 2003, the income generated by the assets sold was immaterial.

Powder River Basin Coal Bed Methane. The Company continues to develop its Powder River Basin coal bed methane reserves and expand the associated gathering system. During the years ended December 31, 2005, 2004 and 2003, the Company expended approximately $174.5 million, $106.9 million and $71.0 million, respectively, on this project.

Greater Green River Basin. The Company's assets in southwest Wyoming and northwest Colorado include the Granger and Lincoln Road facilities (collectively the "Granger Complex"), the Company's 50% equity interest in Rendezvous Gas Services, L.L.C. ("Rendezvous"), the Patrick Draw facility, the Red Desert facility, the Wamsutter gathering system, and production from the Jonah Field, Pinedale Anticline and Sand Wash areas. During the years ended December 31, 2005, 2004 and 2003, the Company expended approximately $108.2 million, $63.9 million and $102.5 million, respectively, in this area.

In February 2006, the Company signed an agreement for the purchase of certain CBM properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming from an undisclosed seller for approximately $136.7 million before adjustments. Closing is expected to occur on or before March 15, 2006 and will be funded with amounts available under the Company's revolving credit facility. The purchase price includes the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. Approximately 70 of the drilled wells are currently dewatering and the remaining 40 wells are awaiting hookup.

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 non-controlled investments is accounted for by the equity method. The Company proportionately consolidates less than 100 percent-owned affiliate partnerships in which the company has an undivided interest.

Inventories. The cost of gas and NGL inventories are determined by the weighted average cost method on a location-by-location basis. Gas and NGL inventory which has been sold forward is accounted for on a specific identification basis. Product inventory is accounted for at the lower of cost

or market and includes $127.4 million and $88.8 million of gas and $2.9 million and $1.6 million of NGLs at December 31, 2005 and 2004, respectively.

Property and Equipment. Property and equipment is recorded at cost, including capitalized interest. 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 hydrocarbon reserves serviced by the equipment.

In connection with the adoption of SFAS No. 143 on January 1, 2003, a review was completed of the Company's operating assets. As a result of this evaluation, the operating lives and salvage values of the associated equipment was reevaluated, and the Company extended the useful life of many of its operating assets and adjusted the estimated salvage value of its operating equipment. These adjustments resulted in an approximate $10.7 million, or $0.10 per share of common stock—assuming dilution, decrease in depreciation, depletion and amortization in the year ended December 31, 2003, from the expense calculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of the Company's assets were treated as a revision of an estimate and were accounted for on a prospective basis.

In December 2004, the Company placed into service a new 200 MMcf per day processing facility adjacent to its Granger Complex. This facility straddles a third-party regulated pipeline and processes its gas to meet pipeline specifications. The facility's capacity is contractually committed to this service, and the contract for processing this gas requires a monthly charge to be paid by the pipeline regardless of the amount of gas processed. These fees total approximately $2.2 million per year and the contract has a remaining term of nine years. In accordance with EITF 01-08, "Determining Whether an Arrangement Contains a Lease", facilities that are built to provide services to one specific customer should be evaluated for potential treatment as capital leases. The Company has determined that accounting for this contract as a capital lease is appropriate. On the Consolidated Balance Sheet, at December 31, 2005 and 2004 related to this transaction, the Company had receivables of $20.6 million and $22.4 million, respectively, in Other assets for the fixed portion of the non-current future lease payments plus the unguaranteed residual value at the end of the lease term and $2.2 million for both years in Other Current assets. The Company also had deferred revenue on the Consolidated Balance Sheet at December 31, 2005 and 2004 totaling $15.7 million and $17.8 million, respectively, in Other long-term liabilities for the non-current deferred revenue and $2.0 million for both years in Accrued expenses for the current portion.

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. Upon surrender or impairment of undeveloped properties, the original cost is charged against income. Developed and undeveloped leaseholds with proved reserves are depleted by the units-of-production method based on estimated proved reserves. Development costs and related equipment are depleted and depreciated by the units-of-production method based on estimated proved developed reserves.

Exploratory lease rentals and geological and geophysical costs are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination of whether a well has found proved reserves is based on a process that relies on interpretations of available geological, geophysical, and engineering data. If an exploratory well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be

carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made, and ii) drilling of additional exploratory wells is under way or firmly planned for the near future. If the drilling of additional exploratory wells in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to expense.

The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2005, 2004 and 2003 (000s).

	2005			2004			2003
Beginning balance at January 1,	$	48,546		$	25,083		$	18,795
Additions to capitalized exploratory well costs pending the determination of proved reserves		66,954			30,683			12,804
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(11,857	)		(6,900	)		(4,655	)
Capitalized exploratory well costs charged to expense		(1,847	)		(320	)		(1,861	)

Ending balance at December 31,	$	101,796		$	48,546		$	25,083

Period end capitalized exploratory well costs (000s) and number of gross wells at December 31, 2005:

			Number of wells
Exploratory well costs capitalized for a period of one year or less	$	66,874	426
Exploratory well costs capitalized for a period of between one and two years		20,900	288
Exploratory well costs capitalized for a period of between two and three years		5,935	72
Exploratory well costs capitalized for a period of between three and four years		5,467	96
Exploratory well costs capitalized for a period of more than four years		2,620	99

Total exploratory well costs capitalized at December 31, 2005	$	101,796	981

Substantially all of the Company's exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, the Company drills wells into various coal seams. These wells are completed and lease-operating costs are being incurred. In order to produce gas from the coal seams, a period of dewatering lasting from a few to thirty-six months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering, and to classify the reserves as proved. In order to accelerate the dewatering time, the Company drills additional exploratory wells in these areas.

Effective January 1, 2004, the Company redefined the asset groupings for the calculation of depreciation and depletion on its oil and gas properties from a well-by-well basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin. This change resulted in an increase in Depreciation, depletion and amortization expense of $4.9 million in 2004. The change in the depreciation and depletion methodology is treated as a change in accounting principle. Accordingly, the Accumulated depreciation, depletion and amortization for these assets has been recalculated under the new methodology. The cumulative effect of the change in depreciation and depletion methodology for the year ended December 31, 2004 was a benefit of $4.7 million, net of tax and is presented in the Consolidated

Statement of Operations under the caption Cumulative effect of change in accounting principle, net of tax.

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 two subsidiaries in Canada. The functional currency of these subsidiaries is the Canadian dollar. The assets and liabilities associated with these subsidiaries 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. The translation change for the years ended December 31, 2005, 2004 and 2003 were ($1.6) million, $816,000 and $1.2 million, respectively, net of tax, included as a separate component in Stockholders' equity.

Revenue Recognition. In the Gas Gathering, Processing and Treating segment, the Company recognizes revenue for its services at the time the service is performed. The Company records revenue from its gas and NGL marketing activities, including sales of the Company's equity production, upon transfer of title. In accordance with EITF 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes as Defined in Issue No. 02-3", the Company records revenue on its physical gas and NGL marketing activities on a gross basis versus sales net of purchases basis because it obtains title to all the gas and NGLs that it buys including third-party purchases, bears the risk of loss and credit exposure on these transactions, and it is the Company's intention upon entering these contracts to take physical delivery of the product. Gas imbalances on the Company's production are accounted for using the sales method. Gas imbalances on the Company's production at December 31, 2005 and 2004 are immaterial. For its marketing activities the Company utilizes mark-to-market accounting for its derivatives. In the Transportation segment, the Company realizes revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. See additional discussion in "Note 9—Business Segments and Related Information".

In order to minimize transportation costs or make product available at a location of the customer's preference, from time to time, the Company will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location. In accordance with EITF 04-13, these transactions will be required to be reported on a sales net of purchases basis. This EITF is effective for transactions entered into or modified after March 15, 2006. To the extent transactions are required to be netted, it will result in a reduction of revenues and costs by an equal amount, but will have no impact on net income or cash flows. For the years ended December 31, 2005, 2004 and 2003, the Company recorded revenues of $148.7 million, $92.6 million and $95.5 million, respectively, and product purchases of $140.8 million, $86.7 million and $84.2 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counter party at different locations and at market prices at those locations.

Accounting for Derivative Instruments and Hedging Activities. The Company recognizes the change in the market value of all derivatives as either assets or liabilities in the statement of financial position, and measures 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. See additional discussion in "Note 4-Commodity Risk Management"

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 accumulated gains on cash flow hedges at December 31, 2005 totaled $2.7 million and will be reclassified into earnings during 2006. These items are separately reported on the Consolidated Statement of Changes in Stockholders' Equity.

Impairment of Long-Lived Assets. The Company reviews its long-lived assets whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's assets are evaluated at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. In order to determine whether an impairment exists, the Company compares its net book value of the asset to the undiscounted expected future net cash flows, primarily determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities or oil and gas properties. If an impairment exists, write-downs of assets are based upon the fair market value of the asset, usually based on expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. For unevaluated oil and gas properties, the Company annually reviews its development plans and drilling history in that area to determine if an impairment of those properties is warranted.

The Company reviews its assets at the plant facility, the related group of plant facilities or the oil and gas producing field or producing coal seam level. Prior to 2003, the Company completed its impairment analysis on its oil and gas producing properties on an individual well-by-well basis. In the fourth quarter of 2003, the Company conducted a review of its oil and gas producing properties, which included an evaluation of the geologic formations and production history for the Company's producing properties. This review indicated that the cash flows from individual wells in its operating areas were not largely independent of the cash flows of other wells producing in the same field or coal seam. As a result of this review, the Company redefined the asset groupings to a field wide analysis for impairment for the Jonah, Pinedale and Sand Wash Basins and a grouping of all wells drilled into related coal seams for the Powder River Basin. These asset groupings were used to determine if any impairment was necessary for the years ended December 31, 2005, 2004 and 2003, and it was determined that none of the asset groups were impaired.

Asset Retirement Obligations. The Company accounts for asset retirement obligations in accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), which was adopted by the Company on January 1, 2003. SFAS 143 requires the Company to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Under the provisions of SFAS 143, asset retirement obligations are capitalized as part of the carrying value of the long-lived asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense through depreciation or depletion of the asset. The majority of the Company's asset retirement obligations relate to dismantling plants and related facilities and reclaiming the sites and plugging and abandoning oil and gas wells. The Company adopted SFAS No. 143 on January 1, 2003 and recorded an $11.5 million increase to Property and equipment, a $4.4 million increase to Accumulated depreciation, depletion and amortization, a $17.8 million increase to Other long-term liabilities and a $6.7 million non-cash, after-tax loss from the Cumulative effect of a change in accounting principle.

The following is a reconciliation of the asset retirement obligation for the years ended December 31, 2005 and 2004 (000's):

	2005			2004
Asset retirement obligation as of January 1	$	32,664		$	20,644
Liability accrued upon capital expenditures		13,315			3,562
Changes due to revisions of estimated retirement costs		1,472			7,262
Liability settled		(539	)		(139	)
Accretion of discount expense		2,940			1,335

Asset retirement obligation as of December 31	$	49,852		$	32,664

Earnings Per Share of Common Stock. Earnings per share of common stock are computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings per share of common stock—assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income attributable to common stock is net income less preferred stock dividends. The following table presents the dividends declared by the Company for each class of its outstanding equity securities (000's, except per share amounts):

	Year Ended December 31,
	2005		2004		2003
Common Stock	$	17,042	$	12,847	$	6,684
Preferred Stock		—		835		6,783

Total Dividends Declared	$	17,042	$	13,682	$	13,467

Dividends Declared Per Share:
Common Stock	$	0.22	$	0.18	$	0.10
Preferred Stock		—	$	0.81	$	2.82

Common stock options, unvested restricted stock granted and, until the final conversion or redemption in April 2004, the Company's $2.625 cumulative convertible preferred stock are potential common shares. The following is a reconciliation of the weighted average shares of common stock outstanding to the weighted average common shares outstanding—assuming dilution. The share information presented reflects the two-for-one common stock split completed in 2004.

		Year Ended December 31,
		2005	2004	2003
Weighted average shares of common stock outstanding		74,409,704	72,419,980	66,412,229
Potential common shares from:
	Common stock options	1,790,427	1,074,767	1,413,353
	$2.625 Cumulative Convertible Preferred Stock	—	—	6,868,838

Weighted average shares of common stock outstanding—assuming dilution		76,200,131	73,494,747	74,694,420

The calculation of fully diluted earnings per share reflects potential common shares, if dilutive, and any related preferred dividends.

Concentration of Credit Risk. Financial instruments that 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 related to trade accounts receivable is limited due to the large number of entities comprising the Company's customer base and their dispersion across geographic locations. The Company records its trade accounts receivable at the invoiced amount, which does not include interest. The risk related to OTC swaps and options is limited due to the investment grade nature of the Company's counter-parties and the ability of the Company to clear many of its OTC transactions through the New York Mercantile Exchange ("NYMEX"). For contracts cleared on the NYMEX, the NYMEX guarantees payment or delivery.

The Company continually monitors and reviews the credit exposure to its marketing counter parties. In the second half of 2005, the prices of natural gas and NGLs, and therefore the Company's credit exposures, increased significantly. Additionally, as a result of the damage in the Gulf States caused by hurricanes Katrina and Rita, several of the Company's counterparties experienced a significant amount of damage to their operating assets. In September 2005, one of the Company's customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. At the time of the bankruptcy filing, the Company had an outstanding account receivable from this utility of $4.1 million. In the third quarter of 2005, the Company reserved $800,000 against this amount, which represents its best estimate of the current market value of this receivable. During 2004 and 2003, the Company did not increase its allowance for doubtful accounts. The Company records an allowance for doubtful accounts on a specific identification basis, and the balance in the allowance for doubtful accounts was $829,000 and $648,000, respectively, at December 31, 2005 and 2004.

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, including capitalized interest, was $28.2 million, $22.3 million, and $28.0 million, respectively, for the years ended December 31, 2005, 2004 and 2003. Capitalized interest associated with construction of new projects was $7.7 million, $2.5 million and $1.8 million, respectively, for the years ended December 31, 2005, 2004 and 2003. Income taxes paid were $35.7 million, $9.4 million and $11.1 million, respectively, for the years ended December 31, 2005, 2004 and 2003. At December 31, 2005 and 2004, lease receivables of $22.6 million and $24.6 million, respectively, and unearned revenue liabilities of $17.7 million and $19.8 million, respectively, were recorded for the lease of the Granger 200MMcf per day straddle plant. Asset retirement obligation assets of $14.8 million and $10.7 million were recorded for capitalized assets and asset retirement obligation liabilities of $17.2 million and $12.1 million were recorded for the years ending December 31, 2005 and 2004, respectively. At December 31, 2005 and 2004, the Company had outstanding disbursements to vendors and producers totaling $97.8 million and $66.4 million, respectively, which were reclassified to Accounts payable. The change in outstanding disbursements to vendors and producers is presented as a component of Cash flows from financing activities in the Statement of Cash Flows.

The Company enters into derivative contracts to mitigate the impact of changes in commodity prices on the results of its operations. As these contracts are considered a key component of the Company's operations, the Company classifies the cash flows related to these contracts in Net cash provided by operating activities on the Consolidated Statement of Cash Flows.

Stock Compensation. As permitted under SFAS No. 123, "Accounting for Stock-Based Compensation", 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 amount by which the market price at the date of exercise exceeds the option price. For the years ended December 31, 2005 and 2004, this tax benefit of $7.7 million and $2.5 million, respectively, was credited to Additional paid-in capital.

The Company had options covering 27,000 and 49,438 common shares outstanding at December 31, 2004 and 2003, respectively, which were treated as re-priced options and had no such options outstanding at December 31, 2005. 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 $10.5021 per share. Based on the Company's per share stock price at December 31, 2005, 2004 and 2003 of $47.09, $29.25 and $23.63, respectively; expense of $506,000, $310,000 and $529,000 was recorded in the years ended December 31, 2005, 2004 and 2003, respectively.

In 2005, the Company granted 383,000 shares of restricted common stock to its employees. In conjunction with the grant of restricted common stock, the Company will record as compensation expense over the three-year vesting period, the value of the restricted common stock on the date of grant. Accordingly, the Company recorded compensation expense of $2.4 million related to its restricted stock in the year ended December 31, 2005.

SFAS No. 123 requires pro forma disclosures for each quarter that a Statement of Operations is presented. The following is a summary of the options to purchase the Company's common stock granted during the years ended December 31, 2005, 2004 and 2003, respectively.

	Year Ended December 31,
	2005	2004	2003
1999 Stock Option Plan	—	140,876	—
2002 Stock Option Plan	157,750	956,841	1,129,900
2002 Directors' Plan	32,000	32,000	32,000
2005 Plan	746,726	—	—

Total options granted	936,476	1,129,717	1,161,900

The following is a summary of the weighted average fair value per share of the options granted during the years ended December 31, 2005, 2004 and 2003, respectively.

	Year Ended December 31,
	2005		2004		2003
1999 Stock Option Plan		—	$	13.12		—
2002 Stock Option Plan	$	15.44	$	13.09	$	9.77
2002 Directors' Plan	$	14.79	$	12.13	$	10.70
2005 Plan	$	13.25		—		—

These values were estimated using the Black-Scholes option-pricing model with the following assumptions:

	1999 Stock Option Plan	2002 Stock Option Plan		2002 Directors' Plan		2005 Stock Option Plan
	2005	2004		2003		2005		2004		2003		2005		2004		2003		2005		2004		2003
Risk-free interest rate	—		3.74	%	—			4.37	%		3.77	%		3.47	%		4.38	%		4.46	%		2.59	%		4.27	%	—	—
Expected life (in years)	—		7		—			7			7			7			7			7			7			6		—	—
Expected volatility	—		39	%	—			37	%		39	%		53	%		37	%		40	%		54	%		37	%	—	—
Expected dividends (quarterly)	—	$	0.05		—		$	0.05		$	0.05		$	0.025		$	0.05		$	0.05		$	0.025		$	0.05		—	—

Under SFAS No. 123, the fair market value of the options at the grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense. If the Company had recorded compensation expense for its grants under its stock-based compensation plans consistent with the fair value method under this pronouncement, the Company's net income, income attributable to common stock, earnings per share of common stock and earnings per share of common stock—assuming dilution would approximate the pro forma amounts below (000s, except per share amounts):

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

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, including depletion, during the reporting period. Therefore, the reported amounts of the Company's 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, including price volatility, counterparty credit risk, the success of its drilling programs and other gas supply. The Company's financial condition, results of operations and cash flows 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 by the Company and other producers will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy and tax policies of the federal and state governments, the pace at which permits required for drilling and production operations are obtained, and the availability of foreign oil and gas, none of which are within the Company's control.

SFAS No. 123(R). SFAS No. 123(R), "Share Based Payment" was issued in December 2004 and must be adopted no later than annual periods beginning after June 15, 2005. This pronouncement requires companies to expense the fair value of employee stock options and other forms of stock based compensation. Currently, the Company is complying with the pro forma disclosure requirements of SFAS No. 123, "Accounting for Stock Based Compensation" which are included in "Note 2—Summary of Significant Accounting Policies to Consolidated Financial Statements".

Effective January 1, 2006, the Company will adopt Statement of Financial Accounting Standards No. 123 (revised 2004), "Share-Based Payment," ("SFAS 123(R)") which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options and employee stock purchases related to the Employee Stock Purchase Plan ("employee stock purchases") based on estimated fair values. SFAS 123(R) supersedes the Company's previous accounting under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") for periods beginning in fiscal 2006. In March 2005, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 ("SAB 107") relating to SFAS 123(R). The Company will apply the provisions of SAB 107 in its adoption of SFAS 123(R).

The Company will adopt SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006, the first day of the Company's fiscal year 2006. The Company's Consolidated Financial Statements as of and for the three months ended March 31, 2006 will reflect the impact of SFAS 123(R). In accordance with the modified prospective transition method, the Company's Consolidated Financial Statements for prior periods will not be restated to reflect, and will not include, any impact of SFAS 123(R). Stock-based compensation expense to be recognized under SFAS 123(R) for the three months ended March 31, 2006 will be approximately $2.5 million for stock-based compensation expense related to employee stock options.

SFAS 123(R) requires companies to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in the Company's Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R), the Company accounted for stock-based awards to employees and directors using the intrinsic value method in accordance with APB 25 as allowed under Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). Under the intrinsic value method, with the exception of the Chief Executive Officer and President's Plan, no stock-based compensation expense had been recognized in the Company's Consolidated Statement of Operations, since the exercise price of the Company's stock options granted to employees and directors equaled the fair market value of the underlying stock at the date of grant.

Stock-based compensation expense to be recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense to be recognized in the Company's Consolidated Statement of Operations for the first quarter of fiscal 2006 will include compensation expense for share-based payment awards granted prior to, but not yet vested as of January 1, 2006. This expense will be based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123. Compensation expense for the share-based payment awards granted subsequent to December 31, 2005 will be based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In conjunction with the adoption of SFAS 123(R), the Company will continue its method of attributing the value of stock-based compensation using the straight-line single option method. As stock-based compensation expense recognized in the Consolidated Statement of Operations for the first quarter of fiscal 2006 will be

based on awards ultimately expected to vest, it will be reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In the Company's pro forma information required under SFAS 123, presented in Note 2 under the heading "Stock Compensation", for the periods prior to fiscal 2006, the Company also estimated compensation expense based on awards ultimately expected to vest.

In accordance with the adoption of SFAS 123(R), the Company will continue to use the Black-Scholes option pricing model ("Black-Scholes model") for the valuation of share-based awards. The Company's determination of fair value of share-based payment awards on the date of grant using the Black-Scholes model is affected by the Company's stock price as well as assumptions regarding variables, including, but not limited to the Company's expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. In management's opinion, the Black-Scholes model provides an accurate measure of the fair value of the Company's employee stock options.

On November 10, 2005, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position No. FAS 123(R)-3 "Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards" ("FSP"). This FSP allows the Company to take up to one year from the later of its initial adoption of SFAS 123(R) or the effective date of the FSP to evaluate the available transition alternatives related to the accounting for the tax effects of share-based payment awards. Accordingly, the Company is considering the alternatives and has not yet elected a transition method.

SFAS No. 151. SFAS No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4" was issued in November 2004 and is effective for the Company for inventory costs incurred in fiscal years beginning after June 15, 2005, and will be applied prospectively. SFAS No. 151 amends APB Opinion No. 43, Chapter 4, "Inventory Pricing" to clarify the accounting for abnormal amounts of costs and the allocation of fixed production overheads. The Company believes that the adoption of SFAS No. 151 will not affect its earnings, financial position or cash flows.

EITF No. 04-13. At its September 2005 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty". This Issue addresses the question of when it is appropriate to measure non-monetary purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. EITF 04-13 requires two or more exchange transactions involving inventory with the same counterparty that are entered into in contemplation of one another should be combined for the purposes of evaluating the effect of APB Opinion No. 29, "Accounting for Nonmonetary Transactions".

In order to minimize transportation costs or make product available at a location of our customer's preference, from time to time, the Company will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location. In accordance with EITF 04-13, these transactions will be required to be reported on a sales net of purchases basis. This EITF is effective for transactions entered into or modified after March 15, 2006. To the extent transactions are required to be netted, it will result in a reduction of revenues and costs by an equal amount, but will have no impact on net income or cash flows.

In accordance with EITF 03-11, the Company records revenue on these transactions on a gross basis versus sales net of purchases basis because the Company obtains title to the product that it buys, bears the risk of loss, credit and performance exposure on these transactions, and takes physical delivery of the product. For the years ended December 31, 2005, 2004 and 2003, the Company recorded revenues of $148.7 million, $92.6 million and $95.5 million, respectively, and product purchases of $140.8 million, $86.7 million and $84.2 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counter party at different locations and at market prices at those locations.

FASB Interpretation No. 47. FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143", or FIN 47, was issued in March 2005 and is effective for fiscal periods ending after December 15, 2005. FIN 47 clarifies the term "conditional asset retirement obligation" as used in FASB Statement 143, "Accounting for Asset Retirement Obligations". Conditional asset retirement obligations as used in FASB Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. The Company adopted this interpretation in the fourth quarter of 2005 and the adoption did not have a material impact on its results of operation, financial position or cash flows.

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. It is our policy that all transactions entered into by the Company with its related parties are consummated in the ordinary course of business and on terms that would be comparable to those obtained from third parties.

Fort Union. Fort Union Gas Gathering, L.L.C. ("Fort Union"), owns a gathering pipeline and treater in the Powder River Basin. At December 31, 2005 and 2004, the Company owned an approximate 15% and 13% interest, respectively, in Fort Union and is the construction manager and field operator. The Company accounts for its investment in this entity under the equity method of accounting as it has significant influence over the operations of this entity. Construction and expansions of the gathering header and treating system were project financed by Fort Union. At December 31, 2005, Fort Union had total project financing debt outstanding of $29.2 million. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union's payment of the project financing on a proportional basis, resulting in the Company's guarantee of $4.3 million of the debt of Fort Union. This guarantee is not reflected on the Consolidated Balance Sheet.

The Company has entered into long-term agreements for firm gathering services on 83 MMcf per day of capacity for $0.14 per Mcf on Fort Union. The Company acts as field operator of Fort Union and charges a monthly overhead fee to cover such services. In 2005, 2004 and 2003, the Company received overhead fees from Fort Union totaling $11,000, $43,000 and $(2,000), respectively, and the Company paid to Fort Union a total of $7.2 million, $5.0 million and $6.4 million for gathering services, respectively. At December 31, 2005 and 2004, the Company had a net amount due to Fort Union of $663,500 and $7,000, respectively. At December 31, 2005, the Company's investment in Fort Union totaled $5.4 million and is included in Investments in joint ventures on the Consolidated Balance Sheet.

Rendezvous. At December 31, 2005 and 2004, the Company owned a 50% interest in Rendezvous Gas Services, L.L.C., ("Rendezvous") and the Company serves as field operator of its systems. Rendezvous was formed in 2001 to gather gas for the Company and other third parties along the Pinedale Anticline for blending or processing at either the Company's Granger Complex or at a third-party owned processing facility. The Granger Complex utilizes Rendezvous to deliver significant volumes of gas contractually dedicated to the Granger Complex for processing or blending. In December 2005, approximately 76% of the gas processed or blended at the Granger Complex was delivered to the facility by Rendezvous. The other 50% owner in Rendezvous is a large utility with oil and gas production and gathering and processing assets in the same area. At December 31, 2005, the Company had a total of $31.4 million invested in this venture and is accounted for under the equity method of accounting. The investment is included in Investments in joint ventures on the Consolidated Balance Sheet. The Company charges a monthly overhead fee to act as field operator of Rendezvous and an overhead charge for capital projects it constructs on behalf of the venture. In 2005 and 2004, the Company received overhead fees as field operator from Rendezvous totaling $100,000 for both years and overhead fees on capital projects totaling $24,800 and $42,800, respectively. In 2005 and 2004, the Company paid to Rendezvous a total of $7.4 million and $3.9 million, respectively, for gathering services. At December 31, 2005 and 2004, the Company had a net amount due to Rendezvous of $501,000 and $1.2 million, respectively.

Officer Transactions. In prior years, the Company had 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 were to be forgiven if the employee was continually employed by the Company and upon a resolution of the board of directors. At December 31, 2002, loans related to 55,000 shares of common stock totaling $295,000 were outstanding under these programs. Pursuant to the terms of an agreement entered into in 2001, these loans were forgiven in May 2003. As of December 31, 2003, there were no loans outstanding under these programs and the program is no longer in effect. In prior years, the Company had accrued for the forgiveness of this loan. In October 2001, the Company's former Chief Executive Officer and President retired. The Company had entered into a consulting agreement with this executive providing for a payment of $175,000 that was made 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 its equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow and net income in relation to those anticipated by the Company's operating budget. The second goal is to manage price risk related to the Company's 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, or OTC, market to accomplish these goals. These instruments allow the Company 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.

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

The Company enters into futures transactions on the NYMEX and OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. The Company conducts credit reviews of all of its OTC counterparties and has agreements with many of these parties that contain collateral requirements. The Company generally uses standardized swap agreements that allow for offset of positive and negative OTC exposures with the same counterparty. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by the Company's ability to require a margin deposit from its counterparties based upon the mark-to-market value of their net exposure. The Company is also subject to margin deposit requirements under these same agreements and under margin deposit requirements for its NYMEX transactions. At December 31, 2005 and 2004, the Company had posted margin deposits totaling $31.2 million and $7.9 million, respectively, with various counterparties.

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

All hedging contracts related to our equity production are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Sale of gas or Sale of natural gas liquids when the hedged transactions occur. Realized and unrealized gains or losses represented by the periodic or final cash settlements from economic hedges are included in Price risk management activities on the Consolidated Statement of Operations. Economic hedges are financially settled derivatives that either were not designated or did not qualify as hedges under SFAS No. 133. These are marked-to-market through earnings.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly effective at offsetting 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 the price of the commodity, and if applicable, the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, ensuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the price of the derivative instrument hedging the transaction. In 2004 and 2003, the Company utilized crude oil as a surrogate hedge for natural gasoline, butane and condensate. In 2005, the Company utilized crude oil as a surrogate hedge for natural gasoline and condensate. These hedges were tested for effectiveness at inception and on a quarterly basis thereafter. Regression analysis based on a five-year period of time was used for these tests. In the first quarter of 2004, the Company determined in its quarterly effectiveness testing that its hedges of equity butane production which utilized crude oil puts as a surrogate were no longer effective hedges. Therefore, in the first quarter of 2004, the Company discontinued cash flow hedge accounting treatment on these instruments. The value of these financial instruments remained in Accumulated other comprehensive income and was reclassified to the Company's results of operations in 2004 as the underlying transactions occurred. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the year ended December 31, 2005, 2004 and 2003, the Company recognized losses of $208,000, $159,000 and $110,000, respectively, from the ineffective portions of its hedges.

In 2003, in order to properly align the Company's hedged volumes of natural gas to its forecasted equity production, the Company discontinued hedge treatment on financial instruments for 10 MMcf per day of natural gas and 50,000 barrels per month of ethane. As a result, a pre-tax loss of $2.8 million was reclassified into earnings from Accumulated other comprehensive income. There were no gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedges in 2005 or 2004.

Account balances related to equity hedging transactions at December 31, 2005 were $23.4 million in Current Assets from price risk management activities, $19.3 million in Current Liabilities from price risk management activities, $1.5 million in Deferred income tax payable, net, and a $2.7 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Stockholders' Equity. Based on the commodity prices as of December 31, 2005, the after-tax gain will be re-classified from Accumulated other comprehensive income to Sale of gas or Sale of natural gas liquids during 2006.

Natural Gas Derivative Market Risk. As of December 31, 2005, the Company held a notional quantity of approximately 286 Bcf of natural gas futures, swaps and options extending from January 2006 to October 2008 with a weighted average duration of approximately six months. This was comprised of approximately 105 Bcf of long positions and 181 Bcf of short positions in these instruments. As of December 31, 2004, the Company held a notional quantity of approximately 342 Bcf of natural gas futures, swaps and options extending from January 2005 to October 2006 with a weighted average duration of approximately five months. This was comprised of approximately 151 Bcf of long positions and 191 Bcf of short positions in these instruments.

Crude Oil and NGL Derivative Market Risk. As of December 31, 2005, the Company held a notional quantity of approximately 50,400 MGal of NGL futures, swaps and options extending from January 2006 to December 2006 with a weighted average duration of approximately six months. This was comprised of approximately 25,200 MGal of long positions and 25,200 MGal of short positions in these instruments. As of December 31, 2004, the Company held a notional quantity of approximately 163,800 MGal of NGL futures, swaps and options extending from January 2005 to December 2005 with a weighted average duration of approximately six months. This was comprised of approximately 100,800 MGal of long positions and 63,000 MGal of short positions in these instruments.

Foreign Currency Derivative Market Risk. As a normal part of its 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, 2005, the Company had sold forward contracts for $45.7 million in Canadian dollars in exchange for $38.9 million in U.S. dollars, and the fair market value of these contracts was a loss of $490,000 in U.S. dollars. As of December 31, 2004, the Company had sold forward contracts for $31.3 million in Canadian dollars in exchange for $24.0 million in U.S. dollars, and the fair market value of these contracts was a liability of $2.1 million in U.S. dollars.

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

	December 31,
	2005		2004
Variable Rate Revolving Credit Facility	$	285,000	$	227,000
Master Shelf and Subordinated Notes		145,000		155,000

Total long-term debt	$	430,000	$	382,000

Variable Rate Revolving Credit Facility. At December 31, 2005, the commitment under the revolving credit facility was $700 million and it matures in November 2010. At December 31, 2005, $285.0 million was outstanding under this facility. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries, and these subsidiaries also guarantee the borrowings under the facility.

The borrowings under the Company's credit facility bear interest at Eurodollar rates or a base rate, as requested by it, plus an applicable percentage based on its debt to capitalization ratio. The base rate is the agent's published prime rate. The Company also pays a quarterly commitment fee on undrawn amounts ranging between 0.10% and 0.30%, depending on its debt to capitalization ratio. This fee is paid on unused amounts of the commitment. As of December 31, 2005, the interest rate payable on borrowings under this facility was approximately 5.3% per year. Under the credit facility, the Company is subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0. The credit facility ranks equally with borrowings under the Company's master shelf agreement with The Prudential Insurance Company. This facility has been rated Ba1 by Moody's and BB+ by Standard and Poor's.

Master Shelf Agreement. Amounts outstanding under the Company's master shelf agreement at December 31, 2005 are as indicated in the following table (dollars in thousands):

The Company's borrowings under its master shelf agreement are secured by a pledge of the capital stock of the Company's significant subsidiaries. These subsidiaries also guarantee the borrowings under this facility. All of the borrowings under the Company's master shelf agreement can be prepaid prior to their final maturity by paying a yield-maintenance fee. Under the Company's master shelf agreement, the Company is subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a quarterly test of EBITDA, as defined in the master shelf agreement, to interest for the last four quarters in excess of 3.0 to 1.0.

In December 2004, the Company gave notice to Prudential of its intention to prepay the $25 million note due January 17, 2008. This note bore interest at 6.36% per annum and was prepaid at par on January 18, 2005. To fund the prepayment, the Company issued a new $25 million note to Prudential, due January 2015 and bearing interest at 5.57% per annum. During 2006, the Company will make scheduled payments totaling $10.0 million on this facility. The Company intends to fund this repayment with funds available under 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 tradable notes under the same terms and conditions. The subordinated notes bore interest at 10% per annum. The Company incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and were being amortized over the term of the notes. The Company redeemed the senior subordinated notes in June 2004 using amounts available under the revolving credit facility and an additional borrowing under the master shelf agreement. In connection with this redemption, a prepayment penalty of $7.75 million was paid and expensed and approximately $2.9 million of unamortized offering commissions were expensed.

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2005 (000s):

The Company, using available market information and valuation methodologies, has determined the estimated fair values of the Company's financial instruments as follows (000s):

	December 31, 2005				December 31, 2004
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents	$	27,198	$	27,198	$	390	$	390
Margin deposits		31,217		31,217		7,939		7,939
Trade accounts receivable		413,004		413,004		385,811		385,811
Accounts payable		463,113		463,113		400,672		400,672
Long-term debt		430,000		422,381		382,000		384,544
Derivative contracts	$	20,140	$	20,140	$	15,641	$	15,641

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

Cash and cash equivalents, margin deposits, 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 comprised of fixed and floating rate facilities. The fair market value for the fixed rate debt was estimated using discounted cash flows based upon the Company's current borrowing rates for debt with similar maturities. The floating rate 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 for income taxes for the years ended December 31, 2005, 2004 and 2003 is comprised of (000s):

			2005		2004		2003
Current:
	Federal		$	31,816	$	820	$	4,002
	State and foreign			2,767		1,658		265

		Total Current		34,583		2,478		4,267
Deferred:
	Federal			78,006		69,069		49,567
	State and foreign			2,407		2,131		1,784

	Total deferred			80,413		71,200		51,351

		Total tax provision	$	114,996	$	73,678	$	55,618

Not included above is the tax (expense) and benefit, respectively, allocated to the cumulative effect of a change in accounting principle of approximately ($2.7) million and $4.0 million for the years ended December 31, 2004 and 2003. There were no such items in 2005.

Temporary differences and carry-forwards which give rise to the deferred tax liabilities (assets) at December 31, 2005 and 2004, net of the tax effect of the cumulative change in accounting principle, are as follows (000s):

		2005			2004
Property and equipment		$	329,652		$	280,565
Differences between the book and tax basis of acquired assets			9,727			10,505
Hedging derivatives			1,525			1,795

	Total deferred income tax liabilities		340,904			292,865

Alternative Minimum Tax ("AMT") credit carry-forwards			(20,622	)		(43,412	)

	Total deferred income tax assets		(20,622	)		(43,412	)

	Net deferred income taxes	$	320,282		$	249,453

The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes, before the tax effect of the change in accounting principle, for the years ended December 31, 2005, 2004 and 2003 are summarized as follows (000s):

At December 31, 2005 and 2004, the Company had AMT credit carry-forwards for federal income tax purposes of approximately $20.6 million and $43.4 million, respectively. These carry-forwards have no expiration.

The Company believes that the AMT credit carry-forwards will be realized because they are substantially offset by existing taxable temporary differences reversing 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.

At December 31, 2005, the Company had net operating loss carryovers ("NOLs") for various states which are immaterial and the Company does not expect to benefit from their utilization. Accordingly, a valuation allowance has been recorded against the entire amount of the NOL.

United States of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc., et al., United States District Court, District of Colorado, Civil Action No. 97-D-1427. The Company, along with over 300 other natural gas companies, are defendants in litigation filed on September 30, 1997, in 72 separate actions filed by Mr. Grynberg on behalf of the federal government. The allegations made by Mr. Grynberg are that established gas measurement and royalty calculation practices improperly deprived the federal government of appropriate natural gas royalties and violate 31U.S.C. 3729(a)(7) of the False Claims Act. The cases have been consolidated to the United States District Court for the District of Wyoming. Discovery on the jurisdictional issues is being completed to determine if this matter qualifies as a qui tam, or class, action. The defendants' joint Motion to Dismiss was argued before a special master on March 17 and 18, 2005 and, as a result thereof, the special master has recommended to the court that claims against several of the defendants, including Western, be dismissed. The recommendation is pending before the court.

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30. Western is a defendant in litigation filed on September 23, 1999, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country. The Company along with other natural gas companies filed a motion to dismiss for failure to state a claim. The court denied these motions to dismiss. The court denied plaintiff's motion for certification as a class and, in the third quarter of 2003, the plaintiff amended and refiled for certification as a class. On May 12, 2003, Mr. Price filed a further claim, Will Price et al v. Western Gas Resources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23, relating to certain matters previously removed from the foregoing action. The Company believes that Mr. Price's claims are without merit and intends to vigorously contest the allegations in this case.

J.P. Morgan Trust Company, National Association, in its Capacity as Trustee of the FI Liquidating Trust v. Oneok Inc. et al., United States District Court, for the District of Kansas, Case No. 05-2389CM. On October 17, 2005, the plaintiff, in its capacity as the liquidating trustee of the successor in interest to Farmland Industries, Inc., filed an amended complaint joining the Company and other defendants to this action. The complaint claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly "misleading or knowingly inaccurate reports concerning trade information" to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States. The complaint asserts that these alleged activities had the effect of increasing prices charged by the defendants for natural gas and preventing full and free competition. The plaintiff seeks to recover damages in the amount of the full consideration of its purchases of natural gas during the time period from January 1, 2000 through December 31, 2001, together with its costs of litigation including attorney's fees. The Company believes that the claims are without merit and intends to vigorously contest the allegations in this case.

Learjet, Inc., Cross Oil Refining & Marketing, Inc. Topeka Unified School District 501, on Behalf of Themselves and All Other Similarly Situated Direct Purchasers of Natural Gas in the State of Kansas v. Oneok, Inc. et al, In the District Court of Wyandotte County, Kansas, Civil Action No. 05-CV-1500. On November 4, 2005, the plaintiffs, on behalf of themselves and all others similarly situated, filed an amended Petition for Damages, joining the Company and other defendants to this action. The Petition claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly "misleading or knowingly inaccurate reports concerning trade information" to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States. The complaint asserts that the allegedly anticompetitive effect of the defendant's actions was to artificially inflate the prices paid by the plaintiffs for natural gas. The plaintiffs are bringing the action as a class action on behalf of all persons and entities in Kansas who made direct purchases of natural gas, for their own use and or consumption, during the time period from January 1, 2000 through October 31, 2002. The plaintiffs are seeking judgment for the full consideration of their purchases of natural gas purchased during such time period, together with costs of litigation including attorney's fees. The Company believes that the claims are without merit and intends to vigorously contest the allegations in this case.

Other Litigation. The Company is involved in various other litigation and administrative proceedings arising in the normal course of business. In the opinion of the Company's 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, results of operations or cash flow.

Lease Commitments. As a normal course of the Company's business operations, the Company enters into operating leases for office space and office, communication and transportation equipment. In addition, primarily to support its growing development in the Powder River Basin coal bed development, the Company has entered into operating leases for compression equipment. These leases are classified as operating leases and have terms ranging from one month to ten years. The majority of the leases for compression have purchase options at various times throughout the primary terms of the agreements and have renewal provisions. Rental payments under operating leases have totaled $18.4 million, $15.3 million and $13.8 million in 2005, 2004 and 2003, respectively. Future operating lease payments by year under these leases are as follows (000s):

Firm Transportation Capacity. The Company enters into firm transportation agreements with interstate pipeline companies as a part of its marketing operations and to ensure that its equity production has access to downstream markets. At December 31, 2005, these agreements have terms ranging from one month to twelve years. Payments under these agreements have totaled $38.9 million,

$29.3 million and $26.4 million in 2005, 2004 and 2003, respectively. Future payments by year under these agreements are as follows (000s):

Storage Capacity. The Company enters into storage agreements with various third parties primarily as part of its marketing operations. Payments under these agreements totaled $7.0 million, $6.2 million and $5.2 million in 2005, 2004 and 2003, respectively. As of December 31, 2005, the Company had contracts in place for approximately 17.0 Bcf of storage capacity at various third-party facilities. The associated contract periods have an average term of 32 months. Future payments by year under these agreements are as follows (000s):

Post Retirement Benefits. In the first quarter of 2005, the Company's board of directors approved the Amended and Restated Directors' Health Plan, which is available to persons who were directors as of January 1, 2005. The terms of the Plan provide that for the duration of each director's tenure on the board, the director, and the director's eligible spouse, if any, is entitled to elect to receive substantially similar benefits as provided to executive officers under the Company's group health plan and a supplemental coverage plan. Following each director's retirement from the board, the director, and the director's eligible spouse, if any, will remain entitled to participate in the Plan until reaching the age of Medicare eligibility. Upon a director or covered spouse attaining Medicare eligibility age, Medicare will become the primary health insurance for such person and the Company will at that time provide supplemental health coverage only. In the event that any retired director or spouse, if any, becomes entitled to participate in another employer sponsored health plan and is obligated to bear less than one-half of the cost of such coverage, then that plan will become the primary health coverage for such person for the duration of such entitlement. As of December 31, 2005, a third-party actuary estimates that the present value of total projected benefits under this plan to the directors will total approximately $1.0 million. This amount will be accrued over the remaining period of their current terms. As of December 31, 2005, the Company has accrued $480,000 for this future benefit obligation.

The Company operates in four principal business segments, as follows: Gathering, Processing and Treating; Exploration and Production; Marketing; and Transportation. Management separately monitors these segments for performance against its internal forecast and these segments 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.

Gathering, Processing and Treating. In the Gathering, Processing and Treating segment, collectively with the Marketing and Transportation segments referred to as the midstream operations, the Company connects producers' wells (including those of the Company's Exploration and Production segment) to its gathering systems for delivery of natural gas to its processing or treating plants, processes the natural gas to extract NGLs and treats the natural gas in order to meet pipeline specifications. In some areas, where no processing is required, the Company gathers and compresses producers' gas and delivers it to pipelines for further delivery to market. Except for volumes taken in kind by the Company's producers, the Marketing segment sells the gas and NGLs extracted at most of its facilities.

In this segment, the Company recognizes revenue for its services at the time the service is performed. Included in this segment is the Company's Powder River Basin coal bed methane gathering operation, which gathers gas from producers, including the Company's Exploration and Production segment. In 2003, this service for the Exploration and Production segment was performed under a percentage-of-proceeds contract and in 2004 and 2005, this service was performed under a fee-based contract. The change of contract type had no effect on the Operating profit of either the Gathering, Processing and Treating segment or the Exploration and Production segment.

Substantially all gas flowing through the Company's gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or, in some cases, for the life of the oil and gas lease. Approximately 81% of the Company's plant facilities' gross margin, or revenues at the plant less product purchases, for the month of December 2005 was under percentage-of-proceeds agreements in which the Company is typically responsible for the marketing of the gas and NGLs. Under these agreements, the Company pays producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. Revenue is recognized when the gas or NGLs are sold and the related product purchases are recorded as a percentage of the sale of the product.

Approximately 17% of the Company's plant facilities' gross margin for the month of December 2005 was under contracts that are primarily fee-based from which the Company receives a set fee for each Mcf of gas gathered and/or processed. This type of contract provides the Company 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 or shut in production. Revenue is recognized under these contracts when the related services are rendered.

Approximately 2% of the Company's plant facilities' gross margin for the month of December 2005 was under contracts with "keepwhole" arrangements or wellhead purchase contracts. Under the keepwhole contracts, the Company retains the NGLs recovered by the processing facility and keeps the producers whole by returning to the producers at the tailgate of the plant an amount of gas equal on a Btu basis to the natural gas received at the plant inlet. The keepwhole component of the contracts permits the Company to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, the Company is adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream. Revenue is recognized when the product is sold.

Exploration and Production. The activities of the Exploration and Production segment, also referred to as upstream operations, include the exploration and development of gas properties in the Rocky Mountain area, including those where the Company's gathering and/or processing facilities are located. The Marketing segment sells the majority of the production from these properties and remits to the Exploration and Production segment all of the proceeds from the sales of gas and its proportional share of transportation charges. Also included in this segment are the Company's Canadian exploration and development operations, which are conducted through its wholly owned subsidiary Western Gas Resources Canada Company and which are immaterial for separate presentation.

Marketing. The Company's Marketing segment markets gas and NGLs extracted at its gathering, processing and treating facilities and produced from its exploration and production assets and buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and title passes. Revenues in this segment are sensitive to changes in the market prices of the underlying commodities. The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price. The Company sells its products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Also included in this segment are the Company's Canadian marketing operations, which are conducted through its wholly owned subsidiary WGR Canada, Inc. and which are immaterial for separate presentation.

During the years ended December 31, 2005, 2004 and 2003, the Company sold gas to a variety of customers including end-users, pipelines, energy merchants, local distribution companies and others. In 2005, no single customer accounted for more than approximately 13% of the Company's consolidated revenues from the sale of gas, or 10% of total consolidated revenue. In 2004, no single customer accounted for more than approximately 9% of the Company's consolidated revenues from the sale of gas, or 7% of total consolidated revenue. In 2003, no single customer accounted for more than 6% of the Company's consolidated revenues from the sale of gas, or 5% of total consolidated revenue.

During the years ended December 31, 2005, 2004 and 2003, the Company sold NGLs to a variety of customers including end-users, fractionators, chemical companies, energy merchants and other customers. In 2005, one customer accounted for approximately 23% of the Company's consolidated revenues from the sale of NGLs, or 3% of total consolidated revenue. This customer is a large integrated energy company. In 2004, one customer accounted for approximately 51% of the Company's consolidated revenues from the sale of NGLs, or 7% of total consolidated revenue. This customer is a large integrated energy company. In 2003, two customers accounted for approximately 49% of the Company's consolidated revenues from the sale of NGLs, or 6% of total consolidated revenue. One of these customers is a large integrated energy company and the other is a large petrochemical company.

Transportation. The Transportation segment reflects the operations of the Company's MIGC, Inc. and MGTC, Inc. pipelines. The revenue presented in this segment is derived from transportation of gas for the Company's Marketing segment and third parties. In this segment, the Company realizes revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. The Transportation segment's capacity contracts range in duration from one month to five years.

Segment Information. The following table sets forth the Company's segment information as of and for the three years ended December 31, 2005, 2004 and 2003 (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 domestic Company employees meeting certain service requirements. The Company may make annual discretionary contributions to the plan as determined by the board of directors, and during the two years ended December 31, 2004 and through May 30, 2005, the match of employee contributions was a sliding scale of 60% to 100% of the first 5% of employee compensation based upon years of service. Effective as of June 1, 2005, the match of employee contributions was increased to equal 100% of the first 6% of employee compensation. In addition, employee vesting of Company contributions was accelerated to a three-year vesting period. Contributions are made to Fidelity Management Trust Company, as trustee. The trustee invests the funds in accordance with the participants' investment elections into mutual funds and a fund to purchase the Company's common stock. The discretionary

contributions made by the Company were $3.3 million, $3.1 million and $2.2 million, for the years ended December 31, 2005, 2004 and 2003, respectively. The matching contributions were approximately $2.0 million, $1.5 million and $1.4 million for the years ended December 31, 2005, 2004 and 2003, respectively.

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 30,000 shares of the Company's common stock. During 1999, the board approved options grants covering 30,000 shares 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 reserved 2,000,000 shares of common stock for issuance upon exercise of options under each of the 1993 Plan and the 1997 Plan and 1,500,000 shares of common stock for issuance upon exercise of options under the 1999 Plan. The 1993 Plan terminated on March 29, 2003. The 1997 Plan and the 1999 Plan will terminate on the later of May 21, 2007 and May 21, 2009, respectively, or the date on which all the respective options granted under each of the plans have expired or been exercised in full. Although options covering 745,204 shares are available to be granted under the 1997 Plan, no further options will be granted under this plan. During 2004, options covering 140,876 shares were granted under the 1999 Plan.

Chief Executive Officer and President's Plan ("CEO 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, the Company's Chief Executive Officer and President, non-qualified stock options were granted for the purchase of 600,000 shares of the Company's common stock. The exercise price of the options was equal to $2.50 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. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full. On August 1, 2005, the Company entered into a new employment agreement with Mr. Dea, which due to recent changes in the tax laws required that he exercise, on or before March 15, 2006, 150,000 of the options to purchase shares of the Company's common stock, which vested on November 15, 2005. Otherwise, per this agreement, these options will expire if not exercised.

2002 Non-Employee Directors Stock Option Plan. Effective May 2002, the stockholders approved the 2002 Non-Employee Directors' Stock Option Plan ("2002 Directors Plan") that authorized the granting of options to purchase 220,000 shares of the Company's common stock. The 2002 Directors Plan provides for a three-year vesting schedule while the non-employee director serves on the Company's board. Under this plan, a newly elected non-employee director will be granted 10,000 options to acquire common stock as of the date of election. The 2002 Directors Plan also provides for an annual grant on the date of the Company's annual meeting to each non-employee director of 4,000 options to acquire common stock. The purchase price of the stock under each option shall be the fair market value of the stock at the time such option is granted and no options shall be re-priced. The 2002 Directors Plan requires the non-employee director to exercise the option at the earlier of ten

years from the date of the plan or within five years of the date each portion vests. The non-employee director's right to exercise options under the 2002 Directors Plan is subject to continuous service since the grant was made. If the non-employee director dies or becomes disabled (within the meaning of the 2002 Directors Plan) or a change of control occurs, then all of the options granted to the non-employee director shall become 100% exercisable. The 2002 Directors Plan will terminate on the later of May 17, 2012 or the date on which all options granted under the plan have expired or been exercised in full. During 2005, 2004 and 2003, a total of 32,000, 32,000 and 32,000 options, respectively, were granted under this plan.

2002 Stock Option Plan. Effective May 2002, the stockholders approved the 2002 Stock Incentive Plan ("2002 Plan") that authorized the granting of options to purchase 2,500,000 shares of the Company's common stock. No employee may be granted more than 250,000 options to acquire common stock in any fiscal year. The 2002 Plan requires the employee to exercise the option at the earlier of ten years from the date of the 2002 Plan or within five years of the date each portion vests. The employee's right to exercise options under the 2002 Plan is subject to continuous employment since the grant was made. If the employee dies, becomes disabled (within the meaning of the 2002 Plan) or a change of control occurs, then all of the options granted to the employee shall become 100% exercisable. The 2002 Plan will terminate on the later of May 17, 2012 or the date on which all options granted under the plan have expired or been exercised in full. During 2005, 2004 and 2003, a total of 157,750, 956,841 and 1,129,900 options, respectively, were granted under this plan.

2005 Stock Option Plan. Effective May 2005, the stockholders approved the 2005 Stock Incentive Plan ("2005 Plan") that authorized the granting of options to purchase 2,500,000 shares of the Company's common stock and the granting of 1,500,000 shares of restricted common stock. No employee may be granted more than 250,000 options to acquire common stock or 150,000 shares of restricted common stock in any fiscal year. The 2005 Plan requires the employee to exercise the options at the earlier of five years of the date each portion vests or seven years from the date the options are granted. The employee's right to exercise options under the 2005 Plan is subject to continuous employment since the grant was made. If a change of control occurs, then all of the options granted to the employee shall become 100% exercisable and all restricted shares become vested. The 2005 Plan will terminate on the later of May 6, 2015 or the date on which all options granted under the plan have expired or been exercised in full. During 2005, a total of 746,726 options and 382,545 restricted shares were granted under this plan.

Under each of the 1997, 1999, 2002 and 2005 plans (including the non-employee director plans), the board of directors of the Company determines and designates from time to time those employees of the Company to whom options or restricted shares 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 1997, 1999, 2002 and 2005 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.

The following table summarizes the number of stock options exercisable and available for grant under the Company's benefit plans at December 31, 2005, 2004 and 2003:

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

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

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

Costs. The following tables set forth capitalized costs at December 31, 2005, 2004 and 2003 and costs incurred for oil and gas producing activities for the years ended December 31, 2005, 2004 and 2003 (000s):

		2005			2004			2003
Capitalized costs:
	Proved properties	$	660,500		$	475,448		$	315,635
	Unproved properties		203,563			134,519			83,384

Total			864,063			609,967			399,019
Less accumulated depreciation and depletion			(212,993	)		(149,624	)		(111,658	)

Net capitalized costs		$	651,070		$	460,343		$	287,361

Costs incurred:
Acquisition of properties
	Proved	$	1,339		$	47,775		$	14,202
	Unproved		12,001			36,776			10,279
Development costs			168,352			95,466			60,479
Exploration costs			86,700			38,098			18,089

Total costs incurred		$	268,392		$	218,115		$	103,049

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, 2005, 2004 and 2003 are as follows (000s):

		2005			2004			2003
Revenues from sale of oil and gas:
	Sales	$	13,539		$	10,767		$	5,905
	Inter-segment sales		392,351			251,585			220,107

Total			405,890			262,352			226,012
Production costs			(148,091	)		(106,732	)		(86,800	)
Exploration costs			(10,271	)		(7,093	)		(6,764	)
Depreciation, depletion and amortization			(69,783	)		(46,977	)		(31,385	)
Income tax expense			(111,059	)		(68,426	)		(57,342	)

Results of operations		$	66,686		$	33,124		$	43,721

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 there from 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, results of operations and cash flows.

The following table sets forth information for the years ended December 31, 2005, 2004 and 2003 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves, all of which are in the United States.

	Natural Gas (MMcf)		Crude Oil (MBbls)
December 31, 2002	580,664		1,213
Revisions of previous estimates	(65,474	)	571
Extensions and discoveries	191,751		887
Purchases of reserves in place	14,005		57
Production	(52,222	)	(75	)

December 31, 2003	668,724		2,653

Revisions of previous estimates	(82,300	)	(85	)
Extensions and discoveries	241,300		1,058
Purchases of reserves in place	26,676		112
Sales of reserves in place	(9,072	)	—
Production	(54,892	)	(97	)

December 31, 2004	790,436		3,641

Revisions of previous estimates	(76,519	)	(279	)
Extensions and discoveries	246,449		886
Sales of reserves in place	(2,035	)	—
Production	(62,246	)	(124	)

December 31, 2005	896,085		4,124

Proved developed reserves, included above:
December 31, 2002	265,300		400
December 31, 2003	282,374		823
December 31, 2004	316,563		1,209
December 31, 2005	391,477		1,247

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, or 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. Also included in this caption are asset retirement obligations.

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, 2005, 2004 and 2003 is as follows (000s):

Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 2005, 2004 and 2003 are as follows (000s):

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

Our management evaluated, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) under the Securities Exchange Act of 1934, as of the end of the period covered by this Report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2005, to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Our management's report on internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K.

As of the date of this Report, we have remediated the previously disclosed material weakness in our internal control over financial reporting at December 31, 2004 with respect to accounting for the existence and designation of certain derivative financial instruments, as disclosed in an amendment to our Form 10-K, filed on December 19, 2005, for the year ended December 31, 2004. The remedial action, which occurred in the fourth quarter of 2005, was to implement a formal review control using a checklist to ensure that all contracts accounted for as derivatives are reviewed, on a monthly basis, as to their terms and the markets on which they are traded to reaffirm that each contract meets the definition of a derivative under each qualifying criteria specified in the applicable accounting guidance.

There have not been any other changes in our internal control over financial reporting during the quarter ended December 31, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Pursuant to instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 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 and is hereby incorporated by reference.

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.

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.

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2005 or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period from to

Delaware (State or Other Jurisdiction of Incorporation or Organization)		84-1127613 (I.R.S. Employer Identification No.)
1099 18^th Street, Suite 1200, Denver, Colorado (Address of Principal Executive Offices)		80202 (Zip Code)
(303) 452-5603 Registrant's telephone number, including area code

	Year Ended December 31,
	2005			%		2004		%	2003			%
Sale of gas	$	3,200,886		80.9		$	2,518,281	81.7	$	2,463,757		85.5
Sale of natural gas liquids		654,842		16.5			450,761	14.6		346,109		12.0
Gathering, processing and transportation revenue		106,366		2.7			90,874	2.9		83,672		2.9
Price risk management activities		(9,445	)	(0.2	)		20,051	0.7		(16,386	)	(0.5	)
Other		6,009		0.1			3,201	0.1		2,599		0.1

	$	3,958,658		100.0		$	3,083,168	100.0	$	2,879,751		100.0

	Year Ended December 31,
	2005		2004		2003
Productive Area	2005		2004		2003
Productive Area	Gross	Net	Gross	Net	Gross	Net
Powder River Basin CBM
Productive wells completed:	1,012	477	670	340	536	278
Dry development wells drilled:	0	0	3	1	0	0
Dry exploratory wells drilled:	0	0	4	2	0	0
Pinedale Anticline and Jonah Fields
Development productive wells completed:	93	9	70	7	34	3
Dry exploratory wells drilled:	1	0	0	0	0	0
San Juan Basin
Development productive wells completed:	28	25	1	1	0	0
Exploratory productive wells completed:	5	5	0	0	0	0
Sand Wash Basin
Development productive wells completed:	5	5	3	3	5	5
Exploratory productive wells completed:	0	0	1	1	0	0
Dry exploratory wells completed:	1	1	1	0	1	1
Canada(1)
Development productive wells completed:	1	1	0	0	0	0
Exploratory productive wells completed:	17	17	0	0	0	0
Other(1)
Exploratory productive wells completed:	9	7	8	7	1	0

			Average for the Year Ended December 31, 2005
Transportation Facilities(1)	Year Placed In Service	Transportation Miles	Pipeline Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D)(3)
MIGC	1970	263	130	135
MGTC	1963	251	18	9

Total		514	148	144

Part	Item(s)
I.	1 and 2.	Business and Properties
			General
			Business Strategy
			2006 Capital Budget
			Upstream Operations
				Powder River Basin Coal Bed Methane
				Pinedale Anticline and Jonah Field
				San Juan Basin
				Sand Wash Basin
				Exploration
				Drilling Results
				Production and Reserves Information
			Midstream Operations
				Gas Gathering, Processing and Treating
					Midstream Operating Areas
					Powder River Basin
					Greater Green River Basin
					West Texas
					Oklahoma
					San Juan
					Principal Gathering and Processing Facilities Table
				Transportation Operations
				Marketing
			Environmental
			Competition
			Regulation
			Employees
	1A.	Risk Factors
	1B.	Unresolved Staff Comments
	3.	Legal Proceedings
	4.	Submission of Matters to a Vote of Security Holders
II.	5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
	6.	Selected Financial Data
	7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	7A.	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
	9A.	Controls and Procedures
	9B.	Other Information
III.	10.	Directors and Executive Officers of the Registrant
	11.	Executive Compensation
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	13.	Certain Relationships and Related Transactions
	14.	Principal Accountant Fees and Services
	15.	Exhibits and Financial Statement Schedules

Production Area	Gross Acres Under Lease at December 31, 2005	Net Acres Under Lease at December 31, 2005	Proved Reserves at December 31, 2005 (Bcfe)	Average Net Production for the Year Ended December 31, 2005* (MMcfe/day)	Gross Productive Gas Wells at December 31, 2005	Net Productive Gas Wells at December 31, 2005
Powder River Basin CBM	1,029,000	525,000	339	116	5,180	2,455
Pinedale Anticline and Jonah Field	132,000	24,000	529	41	374	42
San Juan Basin	29,000	28,000	28	11	172	151
Sand Wash Basin	121,000	112,000	24	5	23	23
Red Desert/Washakie/Uinta Fields	60,000	42,000	1	1	5	2
Denver-Julesburg Basin	393,000	339,000	—	—	9	9
Canada	40,000	39,000	—	—	18	17
Central Montana	639,000	557,000	—	—	—	—
Other	22,000	21,000	—	—	10	2

Total	2,465,000	1,687,000	921	174	5,791	2,701

						Average for the Year Ended December 31, 2005
					Gas Throughput Capacity (MMcf/D)(2)	Average for the Year Ended December 31, 2005
Facilities(1)			Year Placed in Service	Gas Gathering System Miles	Gas Throughput Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D)(3)	Gas Production (MMcf/D)(4)	NGL Production (MGal/D)(4)
Texas
	Gomez Treating(5)		1971	389	280	87	78	—
	Midkiff/Benedum Complex		1949	2,359	165	141	91	845
	Mitchell Puckett Treating(5)		1972	126	120	33	21	1
Wyoming
	Coal Bed Methane Gathering		1990	1,403	548	399	362	—
	Desert Springs Gathering(13)		1979	65	10	6	5	22
	Fort Union Gas Gathering(11)		1999	167	635	433	433	—
	Granger Complex(6)		1987	733	332	319	261	363
	Granger Straddle Plant		2004	—	200	124	—	10
	Hilight Complex(6)		1969	658	124	19	14	69
	Kitty/Amos Draw(14)		1969	321	17	4	2	19
	Newcastle(6)		1981	146	5	3	2	21
	Patrick Draw(6)(8)		1997	242	150	58	47	147
	Red Desert(6)(13)		1979	137	42	53	37	97
	Rendezvous(9)		2001	238	325	369	369	—
	Reno Junction(7)		1991	—	—	—	—	112
	Table Rock Gathering		1979	69	20	12	12	—
	Wamsutter Gathering(10)(13)		1979	290	50	52	46	54
	Wind River Gathering		1979	137	80	48	47	—
Oklahoma
	Chaney Dell/Westana		1966	3,418	187	205	181	304
New Mexico
	San Juan River(5)		1955	277	60	26	21	37
Utah
	Four Corners Gathering		1988	150	15	3	2	15
	Yellow Creek(8)(12)		1985	—	—	—	—	88

		Total		11,325	3,365	2,394	2,031	2,204

Plan Category	Number of securities to be issued upon exercise of outstanding options(a)	Weighted-average exercise price of outstanding options(b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(c)
Equity compensation plans approved by security holders	3,230,697	$	25.19	2,640,067	*
Equity compensation plans not approved by security holders	501,600	$	12.38	—

Total	3,732,297	$	23.47	2,640,067

	Year Ended December 31,
	2005			2004			Percent Change
Financial results:
Revenues	$	3,958,658		$	3,083,168		28
Net income		207,474			127,759		60
Earnings per share of common stock		2.79			1.75		57
Earnings per share of common stock—assuming dilution		2.72			1.73		54
Net cash provided by operating activities		396,097			209,159		89
Net cash (used in) investing activities		(448,428	)		(302,455	)	49
Net cash provided by financing activities		79,139			67,570		17
Operating data:
Average gas sales (MMcf/D)		1,171			1,225		(4	)
Average NGL sales (MGal/D)		1,862			1,641		13
Average gas prices ($/Mcf)	$	7.46		$	5.59		33
Average NGL prices ($/Gal)	$	0.96		$	0.75		28

			Payments Due by Period
Contractual Obligations(1)	Total		Due in 2006		Due in 2007-2008		Due in 2009-2010		Due Thereafter
Guarantee of Fort Union Project Financing	$	4,309	$	1,033	$	2,313	$	963	$	—
Operating Leases		72,068		17,313		30,887		19,270		4,598
Firm Transportation Capacity Agreements		244,734		43,156		84,662		59,218		57,698
Firm Storage Capacity Agreements		27,761		8,884		7,857		3,762		7,258
Long-term Debt		430,000		10,000		10,000		285,000		125,000
Interest on Long-term Debt(2)		99,987		23,725		45,555		22,129		8,578

Total Contractual Cash Obligations	$	878,859	$	104,111	$	181,274	$	390,342	$	203,132

Issue Date		Amount		Interest Rate		Final Maturity	Principal Repayment Schedule
July 28, 1995		$	20,000	7.61	%	July 28, 2007	$10,000 on July 28, 2006 and 2007
June 30, 2004			100,000	5.92	%	June 30, 2011	Single payment at maturity
January 18, 2005			25,000	5.57	%	January 18, 2015	Single payment at maturity

	Total	$	145,000

Product	Year	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	2006	40,000 MMBtu per day with an average minimum price of $6.00 per MMBtu and an average maximum price of $10.13 per MMBtu.	Mid-Continent—40,000 MMBtu per day with an average basis price of $0.55 per MMBtu.
		45,000 MMBtu per day with an average minimum price of $9.00 per MMBtu and an average maximum price of $17.25 per MMBtu.	Permian—7,500 MMBtu per day with an average basis price of $0.97 per MMBtu.
		30,000 MMBtu per day from April through December with an average minimum price of $7.00 per MMBtu and an average maximum price of $10.25 per MMBtu	San Juan—7,500 MMBtu per day with an average basis price of $1.38 per MMBtu and 5,000 MMBtu per day from April through December with an average basis price of $1.70 per MMBtu
			Rocky Mountain—20,000 MMBtu per day with an average basis price of $1.44 per MMBtu and 5,000 MMBtu per day from April through December with an average basis price of $1.71 per MMBtu
			NGPL Texas Oklahoma—10,000 MMBtu per day with an average basis price of $0.45 per MMBtu and 20,000 MMBtu per day from April through December with an average basis price of $0.55 per MMBtu

	2007	115,000 MMBtu per day with an average minimum price of $7.00 per MMBtu and an average maximum price of $14.90 per MMBtu.	Mid-Continent—20,000 MMBtu per day with an average basis price of $0.98 per MMBtu. Permian—10,000 MMBtu per day with an average basis price of $1.20 per MMBtu.
			San Juan—10,000 MMBtu per day with an average basis price of $1.77 per MMBtu.
			Rocky Mountain—45,000 MMBtu per day with an average basis price of $2.01 per MMBtu.
			NGPL Texas Oklahoma—30,000 MMBtu per day with an average basis price of $0.55 per MMBtu.
Natural Gasoline	2006	25,000 Barrels per month with an average minimum price of $40.00 per barrel and an average maximum price of $70.00 per barrel.	Not Applicable
Propane	2006	140,000 Barrels per month for April through December with an average minimum price of $0.83 per gallon and an average maximum price of $1.04 per gallon.	Not Applicable

	Fair Value of Contracts at December 31, 2005
Source of Fair Value	Total Fair Value			Maturing In 2006			Maturing In 2007-2008		Maturing In 2009-2010	Maturing Thereafter
Exchange published prices	$	(12,412	)	$	(12,501	)	$	89	—	—
Other actively quoted prices(1)		48,403			42,997			5,406	—	—
Other valuation methods(2)		(15,851	)		(15,851	)		—	—	—

Total fair value	$	20,140		$	14,645		$	5,495	—	—

			December 31,
			2005			2004
ASSETS
Current assets:
	Cash and cash equivalents		$	27,198		$	390
	Trade accounts receivable, net			413,004			385,811
	Margin deposits			31,217			7,939
	Product inventory			136,968			94,604
	Assets from price risk management activities			48,988			19,893
	Deferred tax asset			4,808			17,947
	Other			14,010			12,494

		Total current assets		676,193			539,078

Property and equipment:
	Gas gathering, processing and transportation			1,290,278			1,150,904
	Oil and gas properties and equipment (successful efforts method)			666,306			495,314
	Construction in progress			286,641			150,273

				2,243,225			1,796,491
	Less: Accumulated depreciation, depletion and amortization			(684,904	)		(570,582	)

		Total property and equipment, net		1,558,321			1,225,909

Other assets:
	Gas purchase contracts (net of accumulated amortization of $42,580 and $38,937, respectively)			32,071			27,704
	Assets from price risk management activities			5,495			249
	Investments in joint ventures			36,791			35,729
	Other			25,763			26,676

	Total other assets			100,120			90,358

TOTAL ASSETS			$	2,334,634		$	1,855,345

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	463,113		$	400,672
	Accrued expenses			106,542			60,472
	Liabilities from price risk management activities			34,343			4,321
	Dividends payable			5,660			3,704

		Total current liabilities		609,658			469,169
Long-term debt				430,000			382,000
Liabilities from price risk management activities				—			180
Other long-term liabilities				66,427			51,827
Deferred income taxes, net				325,090			267,400

Total liabilities				1,431,175			1,170,576

Stockholders' equity:
	Common stock, par value $.10; 100,000,000 shares authorized; 75,375,134 and 68,271,802 shares issued, respectively			7,565			7,430
	Treasury stock, at cost; 50,032 common shares in treasury			(788	)		(788	)
	Deferred compensation			(9,244	)		—
	Additional paid-in capital			429,007			392,437
	Retained earnings			471,860			281,428
	Accumulated other comprehensive income			5,059			4,262

		Total stockholders' equity		903,459			684,769

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY			$	2,334,634		$	1,855,345

			$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			Common Stock		Treasury Stock			Unearned Compensation		Additional Paid-In Capital			Retained (Deficit) Earnings			Accumulated Other Comprehensive Income (Loss) Net of Tax			Notes Receivable from Key Employees			Total Stock- holders' Equity
Balance at December 31, 2002			2,760,000		66,155,222	50,032	$	276		$	3,329	$	(788	)	$	—	$	381,066		$	92,773		$	(2,812	)	$	(295	)	$	473,549
Comprehensive income:
	Net income, 2003		—		—	—		—			—		—			—		—			87,935			—			—			87,935
	Translation adjustments		—		—	—		—			—		—			—		—			—			1,237			—			1,237

		Reclassification adjustment for settled contracts	—		—	—		—			—		—			—		—			—			5,272			—			5,272
		Changes in fair value of outstanding hedge positions	—		—	—		—			—		—			—		—			—			127			—			127
		Fair value of new hedge positions	—		—	—		—			—		—			—		—			—			(2,266	)		—			(2,266	)

		Change in accumulated derivative comprehensive income	—		—	—		—			—		—			—		—			—			3,133			—			3,133

	Total comprehensive income, net of tax		—		—	—		—			—		—			—		—			—			—			—			92,305
Stock options exercised			—		415,180	—		—			24		—			—		3,570			—			—			—			3,594
Effect of re-priced options			—		—	—		—			—		—			—		904			—			—			—			904
Officer loans forgiven			—		—	—		—			—		—			—		—			—			—			295			295
Tax benefit related to stock options exercised			—		—	—		—			—		—			—		727			—			—			—			727
Dividends declared on common stock			—		—	—		—			—		—			—		—			(6,684	)		—			—			(6,684	)
Dividends declared on $2.625 cumulative convertible preferred stock			—		—	—		—			—		—			—		—			(6,783	)		—			—			(6,783	)
Conversion of $2.625 cumulative convertible preferred stock			(676,344	)	1,701,400	—		(68	)		85		—			—		(17	)		—			—			—			—
Redemption of $2.625 cumulative convertible preferred stock			(23,656	)	—	—		(2	)		—		—			—		(1,231	)		32			—			—			(1,201	)

Balance at December 31, 2003			2,060,000		68,271,802	50,032	$	206		$	3,438	$	(788	)	$	—	$	385,019		$	167,273		$	1,558		$	—		$	556,706
Comprehensive income:
	Net income, 2004		—		—	—		—			—		—			—		—			127,759			—			—			127,759
	Translation adjustments		—		—	—		—			—		—			—		—			—			816			—			816
	Other comprehensive income from equity affiliates		—		—	—		—			—		—			—		—			—			(780	)		—			(780	)

		Reclassification adjustment for settled contracts	—		—	—		—			—		—			—		—			—			2,266			—			2,266
		Changes in fair value of outstanding hedge positions	—		—	—		—			—		—			—		—			—			16			—			16
		Reduction due to estimated ineffectiveness	—		—	—		—			—		—			—		—			—			(8	)		—			(8	)
		Fair value of new hedge positions	—		—	—		—			—		—			—		—			—			394			—			394

		Change in accumulated derivative comprehensive income	—		—	—		—			—		—			—		—			—			2,668			—			2,668

	Total comprehensive income, net of tax		—		—	—		—			—		—			—		—			—			—			—			130,463
Stock options exercised			—		681,703	—		—			54		—			—		9,939			—			—			—			9,993
Effect of re-priced options			—		—	—		—			—		—			—		646			—			—			—			646
Tax benefit related to stock options exercised			—		—	—		—			—		—			—		2,527			—			—			—			2,527
Dividends declared on common stock			—		—	—		—			—		—			—		—			(12,847	)		—			—			(12,847	)
Dividends declared on $2.625 cumulative convertible preferred stock			—		—	—		—			—		—			—		—			(789	)		—			—			(789	)
Conversion of $2.625 cumulative convertible preferred stock			(2,024,404	)	5,125,228	—		(204	)		255		—			—		(93	)		—			—			—			(42	)
Redemption of $2.625 cumulative convertible preferred stock			(35,596	)	—	—		(2	)		—		—			—		(1,918	)		32			—			—			(1,888	)
Two for one common stock split			—		—	—		—			3,683		—			—		(3,683	)		—			—			—			—

Balance at December 31, 2004			—		74,078,733	50,032	$	—		$	7,430	$	(788	)	$	—	$	392,437		$	281,428		$	4,262		$	—		$	684,769

Comprehensive income:
	Net income, 2005		—	—	—		—		—		—			—			—		207,474			—			—		207,474
	Translation adjustments		—	—	—		—		—		—			—			—		—			(1,585	)		—		(1,585	)
	Other comprehensive income from equity affiliates		—	—	—		—		—		—			—			—		—			138			—		138

		Reclassification adjustment for settled contracts	—	—	—		—		—		—			—			—		—			(394	)		—		(394	)
		Changes in fair value of outstanding hedge positions	—	—	—		—		—		—			—			—		—			—			—		—
		Reduction due to estimated ineffectiveness	—	—	—		—		—		—			—			—		—			(15	)		—		(15	)
		Fair value of new hedge positions	—	—	—		—		—		—			—			—		—			2,653			—		2,653

		Change in accumulated derivative comprehensive income	—	—	—		—		—		—			—			—		—			2,244			—		2,244

	Total comprehensive income, net of tax		—	—	—		—		—		—			—			—		—			—			—		208,271
Stock options exercised			—	918,836	—		—		98		—			—			15,916		—			—			—		16,014
Effect of re-priced options			—	—	—		—		—		—			—			1,376		—			—			—		1,376
Tax benefit related to stock options exercised			—	—	—		—		—		—			—			7,661		—			—			—		7,661
Unearned compensation on restricted stock			—	377,565	—		—		37		—			(9,244	)		11,617		—			—			—		2,410
Dividends declared on common stock			—	—	—		—		—		—			—			—		(17,042	)		—			—		(17,042	)

Balance at December 31, 2005			—	75,375,134	50,032	$	—	$	7,565	$	(788	)	$	(9,244	)	$	429,007	$	471,860		$	5,059		$	—	$	903,459

	2005				2004				2003
	As Reported		Pro forma		As Reported		Pro forma		As Reported		Pro forma
Net income	$	207,474	$	199,328	$	127,759	$	122,597	$	87,935	$	84,495
Net income attributable to common stock		207,474		199,328		126,924		121,762		81,094		77,654
Earnings per share of common stock		2.79		2.68		1.75		1.68		1.22		1.17
Earnings per share of common stock—assuming dilution		2.72		2.63		1.73		1.67		1.18		1.14
Stock-based employee compensation cost, net of related tax effects, included in net income	$	2,238		N/A	$	428		N/A	$	576		N/A
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied		N/A	$	10,384		N/A	$	5,590		N/A	$	4,016

		2005			%		2004		%	2003		%
Income tax before effect of change in accounting principle at statutory rate		$	112,865		35.0		$	68,853	35.0	$	52,597	35.0
State income taxes, net of federal benefit			3,483		1.1			2,125	1.1		1,893
Federal and state effect of non-deductibility of CFTC settlement			—		—			2,518	1.3		—	—
Canada income taxes, effect of disallowed loss on sale of stock and other miscellaneous items			(1,352	)	(0.4	)		182	0.1		1,128	0.8

	Total	$	114,996		35.7		$	73,678	37.5	$	55,618	37.1

			Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
	Sale of gas		$	3,242		$	3,766		$	3,198,980		$	2,317		$	—		$	—		$	3,208,305
	Sale of natural gas liquids			57			—			663,987			—			—			—			664,044
	Equity hedges:
		Gas		(45	)		(7,375	)		—			—			—			—			(7,420	)
		Liquids		(9,201	)		—			—			—			—			—			(9,201	)
	Gathering, processing and transportation revenue			99,677			(162	)		—			6,851			—			—			106,366

Total revenues from unaffiliated customers:				93,730			(3,771	)		3,862,967			9,168			—			—			3,962,094
Inter-segment revenues				1,391,987			402,833			85,708			13,811			38			(1,894,377	)		—
Price risk management activities				23			11,103			(20,571	)		—			—			—			(9,445	)
Interest Income				—			18			23			1			51,975			(52,017	)		—
Other, net				4,586			172			27			—			1,224			—			6,009

Total revenues				1,490,326			410,355			3,928,154			22,980			53,237			(1,946,394	)		3,958,658
Product purchases				1,150,022			4,339			3,902,530			4,502			—			(1,851,193	)		3,210,200
Plant and transportation operating
Expense				112,827			233			314			6,289			—			(4,139	)		115,524
Oil and gas exploration and production expense				—			152,226			—			—			—			(38,632	)		113,594
(Earnings) from equity investments				(10,133	)		—			—			—			—			—			(10,133	)

Segment operating profit				237,610			253,557			25,310			12,189			53,237			(52,430	)		529,473
Depreciation, depletion and amortization				46,722			72,575			141			1,829			7,516			—			128,783
Selling and administrative expense				(6	)		—			—			—			60,157			(38	)		60,113
(Gain) loss from sale of assets				(477	)		4			0			983			—			—			510
Interest expense				5			4			1,492			(855	)		68,967			(52,016	)		17,597

Income before income taxes			$	191,366		$	180,974		$	23,677		$	10,232		$	(83,403	)	$	(376	)	$	322,470

Identifiable assets:
	Other allocated assets		$	11,723		$	11,284		$	257,863		$	45,414		$	523,450		$	(110,212	)	$	739,522
	Equity investments			31,428			—			—			877			1,035,511			(1,031,025	)		36,791
	Property and equipment			814,890			647,323			11			34,762			61,335			—			1,558,321

Total identifiable assets			$	858,041		$	658,607		$	257,874		$	81,053		$	1,620,296		$	(1,141,237	)	$	2,334,634

			Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
	Sale of gas		$	3,666		$	9,554		$	2,495,913		$	1,779		$	—		$	—		$	2,510,912
	Sale of natural gas liquids			5			—			467,081			—			—			—			467,086
	Equity hedges:
		Gas		649			6,720			—			—			—			—			7,369
		Liquids		(16,325	)		—			—			—			—			—			(16,325	)
	Gathering, processing and transportation revenue			84,148			—			—			6,726			—			—			90,874

Total revenues from unaffiliated customers				72,143			16,274			2,962,994			8,505			—			—			3,059,916
Inter-segment revenues				1,051,981			252,797			54,321			14,128			—			(1,373,227	)		—
Price risk management activities				(12	)		—			20,063			—			—			—			20,051
Interest income				—			4			—			1			20,181			(20,186	)		—
Other, net				1,210			12			(43	)		49			1,973			—			3,201

Total revenues				1,125,322			269,087			3,037,335			22,683			22,154			(1,393,413	)		3,083,168
Product purchases				871,426			2,450			2,999,426			4,559			—			(1,337,062	)		2,540,799
Plant and transportation operating expense				92,143			23			(167	)		7,150			—			(3,281	)		95,868
Oil and gas exploration and production expense				—			110,473			—			—			—			(32,865	)		77,608
Earnings from equity investments				(7,124	)		—			—			—			—			—			(7,124	)

Segment operating profit				168,877			156,141			38,076			10,974			22,154			(20,205	)		376,017
Depreciation, depletion and amortization				38,585			47,911			123			1,655			7,262			—			95,536
Selling and administrative expense				—			—			—			—			52,292			(46	)		52,246
(Gain) loss from sale of assets				224			(520	)		—			(15	)		300			1,299			1,288
Loss from early extinguishment of debt				—			—			—			—			10,662			—			10,662
Interest expense				—			42			295			(328	)		39,739			(20,186	)		19,562

Income before income taxes			$	130,068		$	108,708		$	37,658		$	9,662		$	(88,101	)	$	(1,272	)	$	196,723

Identifiable assets:
	Other allocated assets		$	32,042		$	7,160		$	146,248		$	47,457		$	419,139		$	(76,286	)	$	575,760
	Equity investment			35,729			—			—			2,559			570,638			(573,197	)		35,729
	Property and equipment			674,011			463,052			17			36,665			52,733			(569	)		1,225,909

Total identifiable assets			$	741,782		$	470,212		$	146,265		$	86,681		$	1,042,510		$	(650,052	)	$	1,837,398

			Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
	Sale of gas		$	5,041		$	4,746		$	2,476,736		$	1,098		$	—		$	—		$	2,487,621
	Sale of natural gas liquids			11			—			357,504			—			—			—			357,515
	Equity hedges:
		Gas		(2,358	)		(21,505	)		—			—			—			—			(23,863	)
		Liquids		(11,407	)		—			—			—			—			—			(11,407	)
	Gathering, processing and transportation revenue			76,621			—			—			7,051			—			—			83,672

Total revenues from unaffiliated customers				67,908			(16,759	)		2,834,240			8,149			—			—			2,893,538
Inter-segment revenues				1,081,358			221,266			38,510			14,093			—			(1,355,227	)		—
Price risk management activities				(11	)		(866	)		(15,509	)		—			—			—			(16,386	)
Interest income				—			42			—			3			12,490			(12,535	)		—
Other, net				1,967			21			4			42			565			—			2,599

Total revenues				1,151,222			203,704			2,857,245			22,287			13,055			(1,367,762	)		2,879,751
Product purchases				948,518			2,289			2,820,495			2,982			—			(1,317,843	)		2,456,441
Plant and transportation operating expense				82,810			328			318			7,680			—			(2,792	)		88,344
Oil and gas exploration and production expense				—			86,856			—			—			—			(34,610	)		52,246
Earnings from equity investments				(7,356	)		—			—			—			—			—			(7,356	)

Segment operating profit				127,250			114,231			36,432			11,625			13,055			(12,517	)		290,076
Depreciation, depletion and amortization				30,676			33,321			141			1,689			8,078			—			73,905
Selling and administrative expense				—			—			—			—			40,481			(58	)		40,423
(Gain) loss from sale of assets				123			(194	)		—			586			53			(724	)		(156	)
Interest expense				—			24			262			(154	)		38,030			(12,535	)		25,627

Income before income taxes			$	96,451		$	81,080		$	36,029		$	9,504		$	(73,587	)	$	800		$	150,277

Identifiable assets:
	Other allocated assets		$	4,067		$	7,001		$	103,603		$	40,628		$	326,537		$	(66,708	)	$	415,128
	Equity investment			—			—			—			—			632,622			(593,333	)		39,289
	Property and equipment			608,623			288,954			1,531			39,010			57,912			731			996,761

Total identifiable assets			$	612,690		$	295,955		$	105,134		$	79,638		$	1,017,071		$	(659,310	)	$	1,451,178

			Per Share Price Range		1997 Plan	1999 Plan	1999 Directors Plan	CEO Plan	2002 Plan	2002 Directors Plan	2005 Plan
Exercisable:
	December 31, 2005		$	0.01-5.00	—	—	6,600	—	—	—	—
			$	5.01-10.00	6,002	—	—	—	—	—	—
			$	10.01-15.00	—	11,002	—	495,000	—	—	—
			$	15.01-20.00	—	342,608	—	—	534,188	46,662	—
			$	20.01-25.00	—	—	—	—	23	—	—
			$	25.01-30.00	—	28,106	—	—	193,048	6,667	—
			$	30.01-35.00	—	—	—	—	11,667	—	—

	TOTAL				6,002	381,716	6,600	495,000	738,926	53,329	—

	December 31, 2004		$	0.01-5.00	36,536	—	6,600	—	—	—	—
			$	5.01-10.00	11,000	—	—	—	—	—	—
			$	10.01-15.00	—	33,672	—	450,000	—	—	—
			$	15.01-20.00	—	586,038	—	—	395,961	32,000	—
			$	20.01-25.00	—	—	—	—	5,000	—	—

	TOTAL				47,536	619,710	6,600	450,000	400,961	32,000	—

	December 31, 2003		$	0.01-5.00	109,266	—	—	—	—	—	—
			$	5.01-10.00	65,320	800	16,700	—	—	—	—
			$	10.01-15.00	—	71,762	—	300,000	—	—	—
			$	15.01-20.00	—	575,504	—	—	84,882	10,666	—

		TOTAL			174,586	648,066	16,700	300,000	84,882	10,666	—

Available for Grant:
	December 31, 2005			—	—	17,088	—	—	30,501	92,000	1,755,274
	December 31, 2004			—	—	4,500	—	—	122,340	124,000	—
	December 31, 2003			—	—	120,876	—	—	1,006,972	156,000	—

		Per Share Price Range		1993 Plan		1997 Plan		1999 Plan		1999 Directors Plan		CEO Plan		2002 Plan		2002 Directors Plan		2005 Plan
Balance at 12/31/02				110,054		318,810		1,262,766		16,700		600,000		375,994		36,000		—

	Granted	$	16.18-22.33	—		—		—		—		—		1,129,900		32,000		—
	Exercised	$	2.30-18.17	(16,028	)	(144,224	)	(130,402	)	—		—		(36,160	)	—		—
	Forfeited or expired	$	6.63-18.91	(94,026	)	—		(668	)	—		—		(12,866	)	(4,000	)	—

Balance at 12/31/03				—		174,586		1,131,696		16,700		600,000		1,456,868		64,000		—

	Granted	$	23.56-31.06	—		—		140,876		—		—		956,841		32,000		—
	Exercised	$	2.30-19.02	—		(127,050	)	(375,653	)	(10,100	)	—		(168,900	)	—		—
	Forfeited or expired	$	13.32-28.35	—		—		(24,500	)	—		—		(72,209	)	—		—

Balance at 12/31/04				—		47,536		872,419		6,600		600,000		2,172,600		96,000		—

	Granted	$	28.52-50.13	—		—		—		—		—		157,750		32,000		746,726
	Exercised	$	2.30-34.00	—		(41,534	)	(309,016	)	—		(105,000	)	(447,286	)	(16,000	)	—
	Forfeited or expired	$	15.37-31.85	—		—		(12,588	)	—		—		(65,910	)	—		(2,000	)

Balance at 12/31/05				—		6,002		550,815		6,600		495,000		1,817,154		112,000		744,726

Weighted-average remaining contractual life (years)				—		2.4		5.3		0.8		3.7		5.9		4.9		6.1

		1993 Plan			1997 Plan			1999 Plan			1999 Directors Plan			CEO Plan			2002 Plan			2002 Directors Plan			2005 Plan
Balance at 12/31/02		$	9.87		$	4.87		$	16.34		$	2.76		$	12.51		$	16.49		$	18.91		$	—

	Granted		—			—			—			—			—			18.91			19.38			—
	Exercised		(9.21	)		(5.30	)		(11.79	)		—			—			(16.52	)		—			—
	Forfeited or expired		(14.51	)		—			(11.73	)		—			—			(16.48	)		(18.91	)		—

Balance at 12/31/03		$	—		$	4.52		$	16.87		$	2.76		$	12.51		$	18.37		$	19.15		$	—

	Granted		—			—			28.35			—			—			28.45			27.69			—
	Exercised		—			(4.94	)		(16.93	)		(2.76	)		—			(17.86	)		—			—
	Forfeited or expired		—			—			(15.68	)		—			—			(18.67	)		—			—

Balance at 12/31/04		$	—		$	3.37		$	18.72		$	2.76		$	12.51		$	22.83		$	21.99		$	—

	Granted		—			—			—			—			—			34.25			34.00			31.86
	Exercised		—			(3.12	)		(17.50	)		—			(12.51	)		(20.62	)		(24.99	)		—
	Forfeited or expired		—			—			(22.89	)		—			—			(24.39	)		—			(31.85	)

Balance at 12/31/05		$	—		$	5.11		$	19.32		$	2.76		$	12.51		$	24.31		$	24.99		$	31.86

	Operating Revenues		Gross Profit(a)		Income Before Cumulative Effect of Change in Accounting Principle		Earnings Per Share of Common Stock Before Cumulative Effect of Change in Accounting Principle		Net Income		Earnings Per Share of Common Stock		Earnings Per Share of Common Stock— Assuming Dilution
2005 quarter ended:
March 31	$	834,107	$	47,214	$	19,706	$	0.27	$	19,706	$	0.27	$	0.26
June 30		868,026		81,067		37,629		0.51		37,629		0.51		0.50
September 30		961,410		37,355		10,735		0.14		10,735		0.14		0.14
December 31		1,295,115		235,054		139,404		1.87		139,404		1.87		1.82

	$	3,958,658	$	400,690	$	207,474	$	2.79	$	207,474	$	2.79	$	2.72

2004 quarter ended:
March 31	$	779,680	$	62,594	$	29,720	$	0.42	$	34,434	$	0.49	$	0.49
June 30		725,838		61,033		13,649		0.19		13,649		0.19		0.18
September 30		693,679		44,922		19,465		0.26		19,465		0.26		0.26
December 31		883,971		111,932		60,211		0.81		60,211		0.81		0.80

	$	3,083,168	$	280,481	$	123,045	$	1.68	$	127,759	$	1.75	$	1.73

	2005			2004			2003
Future cash inflows	$	6,633,731		$	3,872,043		$	3,152,573
Future production costs		(1,865,312	)		(950,891	)		(710,999	)
Future development costs		(499,934	)		(411,257	)		(275,302	)
Future income tax expense		(1,408,954	)		(838,615	)		(740,314	)

Future net cash flows		2,859,531			1,671,280			1,425,958
10% annual discount for estimated timing of cash flows		(1,439,269	)		(872,035	)		(740,598	)

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	1,420,262		$	799,245		$	685,360

	2005			2004			2003
As of January 1,	$	799,245		$	685,360		$	360,652
Sales and transfers of oil and gas produced, net of production costs		(257,800	)		(155,620	)		(139,211	)
Net changes in prices and production costs related to future production		678,939			(35,978	)		578,659
Development costs incurred during the period		168,352			95,466			60,479
Changes in estimated future development costs		(82,773	)		(78,593	)		(22,565	)
Changes in extensions and discoveries		579,649			365,896			272,110
Revisions of previous quantity estimates		(282,097	)		(161,703	)		(321,395	)
Purchases (sales) of reserves in place		(4,684	)		25,643			22,898
Accretion of discount		120,064			104,118			53,655
Net change in income taxes		(298,633	)		(45,344	)		(179,922	)

As of December 31,	$	1,420,262		$	799,245		$	685,360

3.1		Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2		Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3		Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
3.4		Amended and Restated Bylaws of Western Gas Resources, Inc., adopted by the Board of Directors on January 13, 2006 (previously filed as Exhibit 3.01 to our Current Report on Form 8-K filed on January 19, 2006 and incorporated herein by reference).
4.1		Rights Agreement, dated as of March 22, 2001 between Western Gas Resources, Inc., and Fleet National Bank as Rights Agent, including exhibits thereto (previously filed as Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
4.2		Indenture between Western Gas Resources, Inc. and Guarantors to Chase Bank of Texas, National Association, Trustee for $225,000,000 Senior Subordinated Notes Due 2009, dated June 15, 1999 (previously filed as Exhibit 28 to our Quarterly Report on Form 10-Q filed on August 13, 1999 and incorporated herein by reference).

4.3		Western Gas Resources, Inc. First Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated October 19, 1999 (previously filed as Exhibit 4.10 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
4.4		Western Gas Resources, Inc. Second Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated September 29, 2000 (previously filed as Exhibit 4.11 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
4.5		Western Gas Resources, Inc. Third Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated January 3, 2001 (previously filed as Exhibit 4.12 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
10.1		Registration Rights Agreement among Western Gas Resources, Inc., WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas Company and Sauvage Gas Service, Inc. (previously filed as Exhibit 10.14 to our Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference).
10.2		Amendment No. 1 to Registration Rights Agreement, dated as of May 1, 1991, between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc., Dean Phillips, Inc., Heetco, Inc. NV, Sauvage Gas Company and Sauvage Gas Service, Inc. (previously filed as Exhibit 4.2 to our Quarterly Report on Form 10-Q filed for the quarter ended June 30, 1991 and incorporated herein by reference).
10.3		Third Amended and Restated Master Shelf Agreement, dated as of December 19, 1991 (effective as of January 13, 2003), by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management Company, Inc. and ING Life Insurance & Annuity Company (previously filed as Exhibit 10.29 to our Annual Report on Form 10-K filed on March 24, 2003 and incorporated herein by reference).
10.4		Letter Amendment No. 1 to Third Amended and Restated Master Shelf Agreement, dated as of April 24, 2003, by and among Western Gas Resources, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc. and ING Life Insurance & Annuity Company (previously filed as Exhibit 10.5 to our Quarterly Report on Form 10Q filed on May 13, 2003 and incorporated herein by reference).
10.5		Letter Amendment No. 2 to Third Amended and Restated Master Shelf Agreement, dated as of June 29, 2004, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc., ING Life Insurance & Annuity Company and each Purchaser listed on the Purchaser Schedule attached Thereto (previously filed as Exhibit 10.6 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).
10.6		Letter Amendment No. 4 to Third Amended and Restated Master Shelf Agreement, dated as of November 22, 2005, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc. and each Purchaser listed on the Purchaser Schedule attached thereto (previously filed as Exhibit 10.6 to our Current Report on Form 8-K filed on November 25, 2005 and incorporated herein by reference).

10.7		Amended and Restated Credit Agreement, dated as of November 22, 2005, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, BNP Paribas, JPMorgan Chase Bank, The Royal Bank of Scotland plc, Wachovia Bank, National Association of Wells Fargo Bank, N.A., as Co-Syndication Agents, Fortis Capital Corp., Union Bank of California, N.A., as Co-Documentation Agents, and the Other Lenders a Party thereto (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on November 25, 2005 and incorporated herein by reference).
10.8		Continuing Guaranty, dated as of November 22, 2005, by MIGC, Inc., Western Gas Resources—Texas, Inc., Mountain Gas Resources, Inc., Lance Oil & Gas Company, Inc. and Western Gas Wyoming, L.L.C. in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on November 25, 2005 and incorporated herein by reference).
10.9		Stock Pledge Agreement, dated as of November 22, 2005, by Western Gas Resources, Inc., in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on November 25, 2005 and incorporated herein by reference).
10.10		Foreign Subsidiary Stock Pledge Agreement dated as of December 22, 2005, by Western Power Services, Inc., in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.4 to our Current Report on Form 8-K filed on November 25, 2005 and incorporated herein by reference).
10.11		Amended and Restated Intercreditor Agreement, dated as of November 22, 2005, by and among the Banks, Bank of America, N.A., as Administrative Agent for the Banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc., Pruco Life Insurance Company of New Jersey, Gibraltar Life Insurance Co., Ltd., RGA Reinsurance Company, American Bankers Life Assurance Company of Florida, Inc., Fortis Benefits Insurance Company and Connecticut General Life Insurance Company, consented to and agreed by Western Gas Resources, Inc. and its subsidiaries listed therein (previously filed as Exhibit 10.5 to our Current Report on Form 8-K filed on November 25, 2005 and incorporated herein by reference).
10.12		Credit Agreement, dated as of April 24, 2003, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Bank One, NA and Fleet National Bank, as Co-Syndication Agents, The Royal Bank of Scotland plc and Wachovia Bank, National Association, as Co-Documentation Agents, and the Other Lenders Party Thereto (previously filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q filed on May 13, 2003 and incorporated by reference herein).
10.13		Intercreditor Agreement, dated as of April 24, 2003, by and among the banks (as defined therein), Bank of America, N.A., as Administrative Agent for the banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, ING Life Insurance & Annuity Company and Prudential Investment Management, Inc., consented to agreed by Western Gas Resources, Inc. and its subsidiaries listed therein (previously filed as Exhibit 10.3 to Western Gas Resources, Inc., 10-Q dated March 31, 2002 and incorporated herein by reference).
10.14		Restated Retirement Plan of Western Gas Resources, Inc., dated May 1, 2001 (previously filed as Exhibit 4.9 to our Registration Statement on Form S-8 filed on August 14, 2002 and incorporated herein by reference).
10.15		Western Gas Resources, Inc., 1997 Stock Option Plan (previously filed as Exhibit 10.29 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*

10.16		First Amendment to the Western Gas Resources, Inc. 1997 Stock Option Plan (previously filed as Exhibit 10.30 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.17		Second Amendment to the Western Gas Resources, Inc. 1997 Stock Option Plan (previously filed as Exhibit 10.31 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.18		Western Gas Resources, Inc., 1999 Stock Option Plan. (Previously filed as Exhibit 4.7 to our Registration Statement on Form S-8, Registration No. 333-95255, filed on January 24, 2000 and incorporated herein by reference).*
10.19		First Amendment to the Western Gas Resources, Inc. 1999 Stock Option Plan (previously filed as Exhibit 10.33 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.20		Second Amendment to the Western Gas Resources, Inc. 1999 Stock Option Plan (previously filed as Exhibit 10.34 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.21		Western Gas Resources, Inc. 2002 Stock Option Plan (previously filed as Exhibit 10.35 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.22		First Amendment to the Western Gas Resources, Inc. 2002 Stock Option Plan (previously filed as Exhibit 10.36 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.23		Western Gas Resources, Inc. Non-Employee Director's Stock Option Plan (previously filed as part of Exhibit 4.7 to our Registration Statement on Form S-8, Registration No. 333-95259, filed on January 24, 2000 and incorporated herein by reference).*
10.24		Western Gas Resources, Inc. 2002 Non-Employee Director's Stock Option Plan (previously filed as Exhibit 10.38 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.25		Stock Option Agreement, effective November 1, 2001, by and between Western Gas Resources, Inc. and Peter A. Dea (previously filed as Exhibit 99.1 to our Registration Statement on Form S-8 filed on December 21, 2002, and incorporated herein by reference).*
10.26		Western Gas Resources, Inc. 2005 Stock Incentive Plan (previously filed as Exhibit 4.7 to our Registration Statement on Form S-8 filed on May 31, 2005 and incorporated herein by reference).*
10.27		2001 Employment Agreement, dated June 14, 2001, by and between Western Gas Resources, Inc. and Edward A. Aabak, together with 2001 Indemnification Agreement (previously filed as Exhibit 10.41 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.28		2001 Employment Agreement, dated June 14, 2001, by and between Western Gas Resources, Inc. and John F. Chandler, together with 2001 Indemnification Agreement (previously filed as Exhibit 10.42 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.29		2001 Employment Agreement, dated October 15, 2001, by and between Western Gas Resources, Inc. and William J. Krysiak, together with 2001 Indemnification Agreement (previously filed as Exhibit 10.43 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*

10.30		2001 Employment Agreement, dated June 14, 2001, by and between Western Gas Resources, Inc. and John C. Walter, together with 2001 Indemnification Agreement (previously filed as Exhibit 10.44 to our Annual Report on Form 10-K filed on March 11, 2004 and incorporated herein by reference).*
10.31		Employment Agreement, dated August 1, 2005, by and between Western Gas Resources, Inc. and Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on August 2, 2005 and incorporated herein by reference).*
10.32		Remuneration of Directors (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 21, 2005 and incorporated herein by reference).*
10.33		Amended and Restated Directors' Health Plan, dated February 23, 2005 (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on March 1, 2005 and incorporated herein by reference).*
11.1		Statement regarding computation of per share earnings.†
21.1		List of Subsidiaries of Western Gas Resources, Inc.†
23.1		Consent of PricewaterhouseCoopers LLP.†
23.2		Consent of Netherland, Sewell & Associates, Inc.†
31.1		Section 302 Certification of the Chief Executive Officer.†
31.2		Section 302 Certification of the Chief Financial Officer.†
32.1		Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.†

		WESTERN GAS RESOURCES, INC. (Registrant)
		By:		/s/ PETER A. DEA Peter A. Dea Chief Executive Officer, President and Director
				March 14, 2006 Date