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Western Gas Resources, Inc. Form 10-K Table of Contents
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

FORM 10-K

(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, 2002
or
o	Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
for the transition period from                  to

Commission file number 1-10389

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

Delaware	84-1127613
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1099 18th Street, Suite 1200, Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 452-5603
Registrant's telephone number, including area code

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

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

Securities registered pursuant to Section 12(g) of the Act: None

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

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

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

        The aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2002 was $1,234,329,292.

        The number of shares outstanding of the only class of the registrant's common stock, as of March 3, 2003, was 33,099,577.

DOCUMENTS INCORPORATED BY REFERENCE

        Information required by Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy statement to be filed pursuant to Regulation 14A with respect to the annual meeting of stockholders scheduled to be held on May 16, 2003.

Western Gas Resources, Inc.

Form 10-K

Table of Contents

Part	Item(s)
I.	1 and 2.	Business and Properties
			General
			Business Strategy
			2003 Capital Budget
			Upstream Operations
				Powder River Basin Coal Bed Methane
				Green River Basin
				Sand Wash Basin
				Production Information
			Midstream Operations
				Gas Gathering, Processing and Treating
				Powder River Basin
				Green River Basin
				West Texas
				Oklahoma
				San Juan Basin
				Principal Facilities
				Transportation
				Marketing
			Environmental
			Competition
			Regulation
			Employees
	3.	Legal Proceedings
	4.	Submission of Matters to a Vote of Security Holders
II.	5.	Market for the Registrant's Common Equity and Related Stockholder Matters
	6.	Selected Financial Data
	7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	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
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.	Controls and Procedures
	15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

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

General

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

        Our operations are conducted through the following four business segments:

•

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



•

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



•

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



•

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

        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):

	Year Ended December 31,
	2002			%		2001		%	2000		%
Sale of gas	$	2,123,468		85.3		$	2,849,097	85.0	$	2,628,052	80.1
Sale of natural gas liquids		309,697		12.4			424,082	12.6		590,932	18.0
Processing and transportation revenue		65,601		2.6			55,398	1.6		53,156	1.6
Non-cash change in fair value of derivatives		(13,788	)	(0.5	)		19,906	0.6		—	—
Other		4,720		0.2			4,679	0.2		7,951	0.3
	$	2,489,698		100.0		$	3,353,162	100.0	$	3,280,091	100.0

Business Strategy

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

        Double Proven Natural Gas Reserves and Equity Production of Natural Gas from the level at December 31, 2001 over three to 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, or CBM, and development in the Green River and the Sand Wash Basins and actively seek to add another core natural gas development project. Overall, we have acquired drilling rights on approximately 820,000 net acres in these and other Rocky Mountain basins. At December 31, 2002, we had proved developed and undeveloped reserves of approximately 588 billion cubic feet equivalent, Bcfe, on a portion of this acreage position. In total this represents an increase of approximately 24% in our proved reserves from December 31, 2001. Reserve life, determined by dividing our proved reserves by our 2002 production, is over 12 years. During 2002 our production of natural gas as compared to 2001 increased by 33% to 48.9 Bcfe and we replaced 332% of our 2002 production. All of our 2002 reserve and production growth was achieved on our existing acreage. In the Powder River Basin, future growth potential lies in over 10,000 well locations in the Big George, Wyodak and related coals if the play is fully successful. In the Green River Basin, our reserve potential is in the development of 80-acre and 40-acre locations on our leasehold on the Pinedale Anticline, which target sandstone reservoirs in the Lance and Mesa Verde formations.

        We are also actively seeking to add another core project that is focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands and coal bed methane plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations focused in this area. To further enhance our ability to accomplish this goal, in 2002 we added to the staff of experienced individuals in our exploration and production department, including additional geologists and a reservoir engineer. These individuals bring a new level of expertise in identifying opportunities in the Rocky Mountain region and are actively evaluating several prospects. The addition of another core project will ideally result in new investment opportunities in our midstream operations.

        Meet or Exceed Throughput Projections in our Midstream Operations.     To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections, expansion or acquisition of gathering or processing systems and the consolidation of existing facilities. We also seek growth opportunities for gathering and processing through our development of new gas reserves. These operations provide us with steady throughput volumes and significant cash flow that we can in turn reinvest in new growth opportunities in either our upstream or midstream businesses. Over the last five years, the throughput volume at our gathering and processing facilities has averaged 1.2 Bcf per day and operating income contributed by these facilities has averaged $103.2 million per year.

        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 to Western by third parties or produced by Western. We contract for production from newly developed acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering, processing or treating at our facilities. Historically, while certain individual plants have experienced declines in dedicated reserves, we have been successful in connecting additional reserves to more than offset the natural declines. At December 31, 2002, the estimated reserves connected to our midstream facilities totaled 3.6 Tcf. This includes our estimate of future third-party production and our proven reserves. The estimated third-party reserves connected to our facilities are based upon our interpretation of publicly available well and production information and are not the result of audited reserve reports prepared for us. In 2002, including the reserves developed by us and associated with our partnerships, and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 205% of 2002 throughput. During 2002, we spent approximately $52.5 million on additional well connections and compression and gathering system expansions.

        We will also evaluate investments in expansions or acquisitions of assets that complement and extend our core natural gas gathering, processing, treating and marketing businesses and new growth projects in the Rocky Mountain region. On January 31, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. These systems are comprised of a total of 550 miles of gathering lines and, at January 31, 2003, were gathering a total of 139 MMcf per day. The Green River Basin is one of our core operating areas and these systems will be consolidated into our existing operations in this area. The Wind River Basin systems provide us with the opportunity to expand our gathering and processing activities into an area in which we have not previously operated. The remaining systems will be evaluated for consolidation opportunities or divestiture.

        Optimize Annual Returns.     To optimize our annual returns, we will focus our efforts in our primary operating areas in the Powder River and Green River Basins in Wyoming, the Anadarko Basin in Oklahoma and the Permian Basin in west Texas. We review the economic performance and growth opportunities of each of our 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. In September 2002, we sold our Toca processing facility in Louisiana for $32.2 million, subject to accounting adjustments. This facility, while achieving a satisfactory return, was not located in one of our primary operating areas and did not have significant growth opportunities. The sale of this asset allows us to concentrate our capital investment and manpower on our core operations. Consolidations and joint ventures allow us to increase the throughput of one facility while reducing the capital invested in, and the operating costs of, the consolidated assets. For example, the formation of Rendezvous Gas Services, L.L.C. with Questar Gas Management Company in 2001 increases gas available for processing at our Granger gas processing facility in southwest Wyoming and reduces our capital investment requirements.

        We routinely evaluate our business for methods to reduce our operating and administrative costs, including the implementation of automation and information technology. Replacing and upgrading field equipment allows us to minimize maintenance costs, fuel consumption and field operating costs. Over the last several years, we invested $29.0 million to replace older compression units at our Midkiff/ Benedum facility with fuel-efficient equipment. This upgrade has resulted in reduced emissions and a decrease in our fuel consumption and has accordingly increased the natural gas available for sale and our ability to attract additional volumes to our system.

        This section, as well as other sections in this Form 10-K, contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as "may," "intend," "will," "expect," "anticipate," "estimate," or "continue" or the negative thereof or other variations thereon or comparable terminology. This Form 10-K contains forward-looking statements regarding the expansion of our gathering operations, our project development schedules, our budgeted capital expenditures, success of our drilling activities, our marketing plans and anticipated volumes through our facilities and from production activities that involve a number of risks and uncertainties, including the composition of gas to be treated, drilling schedules, the success of the producers with acreage dedicated to our facilities, and continuing litigation and other disputes with our co-developer in the Powder River Basin. In addition to the important factors referred to herein, numerous other factors affecting our business generally and in the markets for gas and NGLs in which we participate, could cause actual results to differ materially from our projections in this Form 10-K. See further discussion in "Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies—Use of Estimates and Significant Risks."

        Western Gas Resources, Inc. was incorporated in Delaware in 1989. On March 18, 2003, we relocated our principal offices to Denver Place, 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 soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission, or the SEC.

2003 Capital Budget

        In order to maintain a strong balance sheet, our general goal is to limit our capital expenditures, excluding acquisitions, in any single year to 110% of the projected cash flow generated by our operations for that year. In some years, however, we expect that we will exceed this limitation based on the growth and acquisition opportunities available to us. In 2003, we anticipate capital expenditures of approximately $182.3 million. We expect that the Rocky Mountain region will utilize 85% or $155.2 million of the 2003 budget.

        The majority of our capital expenditures will be in the Powder River Basin CBM development and in the Greater Green River Basin. In the Powder River Basin CBM development, we plan to invest approximately $68.0 million, or 37% of our total capital program. Of this amount, approximately $55.2 million will be spent on our share of drilling 845 gross wells and for production equipment and undeveloped acreage and $12.8 million for gathering lines and installation of additional compression units.

        In the Greater Green River Basin we expect to invest approximately $82.3 million, or 45% of the total 2003 capital expenditure program. We plan to spend approximately $18.4 million to participate in approximately 41 gross wells, including three well workovers, the majority of which are in the rapidly developing Pinedale Anticline area and $26.8 million to expand gathering and compression services. In January 2003, we spent a total of $37.1 million for the acquisition of 18 gathering systems, the largest systems of which are located in the Greater Green River Basin.

        The remaining $32.0 million of our 2003 capital spending program is expected to be spent as follows: $19.9 million for midstream operations in other areas, $7.8 million for capitalized interest and overhead and $4.3 million for administrative expenditures. Overall, we expect to spend $11.4 million on maintenance and upgrade projects for existing midstream facilities. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2003 will not change.

Upstream Operations

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

        Powder River Basin Coal Bed Methane.     We continue to develop our Powder River Basin coal bed methane reserves and expand the associated gathering system in northeast Wyoming. The Powder River Basin coal bed methane area is currently one of the largest on-shore plays for the development of natural gas in the United States. Within this area, together with our co-developer, in 2002, we were the largest producer of natural gas. In addition, we are the largest gatherer of natural gas and, through our MIGC pipeline, transport a significant volume of gas out of this basin.

        At December 31, 2002, we held the drilling rights on approximately 515,000 net acres in this basin, and as of December 31, 2002, we had established proven developed and undeveloped reserves totaling 414 Bcfe on a portion of this acreage, 52% of which are proven and developed. This represented an overall 5% increase in proven reserves as compared to December 31, 2001. In total, as a result of our drilling program, we added 169.1 Bcfe of proven reserves in this play in 2002. Partially offsetting these additions was production of 43.4 Bcfe during the year and downward revisions of existing reserves of 105 Bcfe. These downward revisions were the result of several factors including a more stringent interpretation of SEC proved reserve criteria, which resulted in a 23 Bcfe downward revision; pressure depletion caused by offset drainage and our own drilling in the older developed areas which resulted in a downward revision of 11 Bcfe; and new production and core data showing lower resource estimates for the Hoe Creek area and Lower Canyon coal, which resulted in a downward revision of 46 Bcfe. The remaining 25 Bcfe of revisions were in a number of areas and were caused by a number of factors including core data, 40-acre development drainage, well performance and offsetting pressure reduction indicating depletion of un-drilled locations.

        The drilling operations in the Powder River Basin through December 31, 2002 have primarily focused on developing reserves in the Wyodak coal, which is located on the east side of the coal bed development. We participated in the drilling of 909 gross wells in 2002, of which 723 were drilled in the Wyodak coal and 186 were drilled in the Big George coal. We plan to participate in 845 gross wells in 2003, of which 441 are scheduled to be drilled in the Wyodak coal and 404 are scheduled to be drilled in the Big George coal. The average drilling and completion cost for our coal bed methane gas wells is approximately $90,000 to $120,000 per well with average reserves per successful well of approximately 275 MMcf. Our finding and development costs in this area in 2002, excluding reserve revisions, averaged approximately $0.31 per Mcf. The majority of future development will be concentrated on developing the Big George and other coal seams. Much of the Big George coal seam is deeper and thicker than the Wyodak coal. We expect that as wells are drilled and developed in the Big George coal, the gas reserves and production per well and the average drilling and completion cost per well will increase.

        Our share of production from wells in which we own an interest has increased from an average of approximately 105 MMcfe per day in the month of December 2001 to 126 MMcfe per day, excluding prior period revisions, in the month of December 2002. We have experienced a 1.5% decline in production in the month of January 2003 to an average 124 MMcfe per day, excluding prior period adjustments. This decline is primarily due to operational and permitting delays, under-performance of wells in the Hoe Creek area and the timing of the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS. We currently anticipate an average production rate of 132 net MMcfe per day from this area in December 2003.

        As of December 31, 2002, we had participated in the drilling of approximately 3,800 wells in the Powder River Basin CBM play. Of these, approximately 2,900 are producing gas wells; approximately 400 are in the process of being dewatered, which reduces pressure in the coals in order to release gas; and approximately 400 are waiting on connection to gathering systems. The remaining wells that have been drilled have produced all their recoverable reserves. During the first half of 2003, we anticipate that approximately 300 of the 400 wells awaiting connection to gathering systems will be connected and will be put into gas production. The remaining 100 wells will be connected to a gathering system once wider-scale development drilling in the area in which these wells are located commences.

        Industry-wide, production from the Big George coal increased by 293% in 2002 and in early February 2003, production rates totaled approximately 70 MMcf per day from eight separate pilots. We are currently evaluating 11 pilot areas and one development area in the Big George. Through December 31, 2002, we have drilled approximately 425 gross wells in the Big George coal area. We have marketable production quantities in the All Night Creek, Pleasantville and Kingsbury areas. In early February 2003, these areas were producing a combined 27.5 gross MMcf per day. At December 31, 2002, we had proven reserves of 49 Bcfe in the Big George coal, primarily associated with the All Night Creek development area.

        Future drilling on the majority of our federal acreage is contingent on completion of the EIS. The 30-day protest period for the final draft of the EIS ended on February 18, 2003. The Bureau of Land Management's Buffalo, Wyoming field office tentatively plans to issue the final Record of Decision by mid April 2003. That date could be delayed based on the quantity and nature of the protests received on the final EIS. A significant portion of the wells we plan to drill in 2003 would require federal permits to be issued pursuant to the completion of the EIS. We do not expect that any limit on our ability to drill during 2003 will affect the rate of our production until late in 2003. Based on our preliminary review of the final EIS, we expect that the cost and timing of drilling and operating on federal lands in the Powder River Basin may increase but do not expect that any increases will have a material adverse impact on our results of operations or financial position.

        Additionally, the Wyoming Department of Environmental Quality, or DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of wells on our acreage producing from the Wyodak formation drain into these areas. The Wyoming and Montana DEQ offices have reached agreement on procedures for discharging and monitoring water into the Powder River and other drainage areas, in which most of our undeveloped prospects are located. Although the Wyoming and Montana DEQ offices have reached this agreement, the Wyoming DEQ has begun to grant permits only on a limited basis to the Powder River drainage area when it can be demonstrated that none of the discharge water will reach the Powder River itself. Therefore, we can make no assurances that the conditions under which additional permits are granted will not impact the level of drilling or the cost and timing of the associated production.

        On April 26, 2002, the Interior Board of Land Appeals, or IBLA, ruled that the BLM did not comply with the National Environmental Policy Act, or NEPA, prior to issuing three federal oil and gas leases held by an unaffiliated third party in the Powder River Basin. There has not been a final decision regarding the validity of the three leases. The IBLA has remanded the case to the Wyoming BLM State Director without specifying a remedy. The State Director could, among other things, require additional NEPA analysis to be done on these three leases. The EIS is currently being conducted basin wide. This study includes a NEPA analysis covering coal bed methane development. The unaffiliated leaseholder has filed for judicial review in federal district court in Wyoming. We do not have any interests in these leases nor have we received notice of any challenge to leases that we hold. We are continuing to monitor the development of the issue.

        Our 2003 capital budget in the Powder River Basin coal bed development includes approximately $55.2 million for drilling costs, production equipment and lease acquisitions. During 2002, our capital expenditures in these activities totaled $51.9 million. Depending upon future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. In addition, due to regulatory uncertainties, which are beyond our control, we can make no assurance that we will incur this level of capital expenditure. Our co-developer in this area is also required to make similar capital commitments to continue the pace of the development as planned. During 2002, our co-developer in this area publicly disclosed that it had financial difficulties. We are currently unable to predict the impact, if any, of our co-developer's financial situation on the future pace of development in the Powder River Basin. Several disputes have arisen between our co-developer and us. These disputes are more fully described in Note 8 to our Consolidated Financial Statements.

        Green River Basin.     Our upstream assets in the Green River Basin of southwest Wyoming are located in the Jonah Field and Pinedale Anticline areas. As of December 31, 2002, we owned approximately 194,000 gross oil and gas leasehold acres, or approximately 32,000 net acres, in these areas. During 2002, we participated in 26 gross wells, or 4 net wells, in these areas, at a cost of $17.3 million and experienced a success rate of 100%. Our capital budget for 2003 in the Jonah Field and Pinedale Anticline areas provides for expenditures of approximately $12.9 million for drilling costs and production equipment. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure. During 2003, we expect to participate in the drilling of 32 gross wells, or approximately 4 net wells on the Pinedale Anticline. The expected drilling and completion costs per gross well range from $3.0 million to $4.0 million and the average well depth in this area approximates 13,000 feet and has average gross reserves per successful well of approximately 4 Bcfe. Our average finding and development costs in 2002 were $0.47 per Mcfe, including new reserves attributable to 40-acre spacing. During December 2002, we produced an average of 19.2 MMcfe per day, net, from these areas. We had established proven developed and undeveloped reserves totaling 161 Bcfe at December 31, 2002. This represents a 133% increase as compared to December 31, 2001 in part due to a 18 Bcfe revision resulting from attributing reserves to all 40-acre proved undeveloped locations. There can be no assurance, however, as to the ultimate recovery of these reserves.

        Sand Wash Basin.     We continue to explore and develop our acreage position in the Sand Wash Basin in northwest Colorado. We own approximately 208,000 gross oil and gas leasehold acres, or approximately 177,000 net acres, in this basin. In December 2002, we were producing an average of 2.7 MMcf per day from this acreage. At December 31, 2002, we had established proven developed and undeveloped reserves totaling 13 Bcfe on a portion of this acreage. This represents a slight increase from the proved reserves at December 31, 2001. The majority of this acreage is in the exploration phase and will be evaluated in 2003 and subsequent years. Our capital budget in this area provides for expenditures of approximately $5.3 million during 2003 for our participation in the drilling of six gross developmental wells, or four net wells, and three workovers of existing wells. The expected drilling and completion costs per gross well are approximately $835,000 to $1.2 million and the average well depth in this area approximates 7,500 feet. Our average finding and development costs in 2002 were $0.44 per Mcfe. During 2002, capital expenditures in this area totaled $1.1 million for our participation in the drilling of 2 gross and net wells.

        Production Information.     Revenues derived from our producing properties comprised approximately 6%, 4% and 2% of consolidated revenues for the years ended December 31, 2002, 2001 and 2000, respectively. The operating margin (revenues and equity earnings from equity investments less product purchases and operating expenses) derived from our producing properties comprised approximately 33%, 24% and 14% of consolidated gross margin for the years ended December 31, 2002, 2001 and 2000, respectively. Primarily as a result of the increased investment in the Powder River Basin coal bed methane, we expect both the revenues and operating margin derived from our producing properties to continue to increase.

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

		Year Ending December 31,
		2002		2001		2000
State/Basin		Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)
Colorado—Sand Wash Basin		900	6	547	3	387	2
Texas(1)		20	2	29	2	36	3
Wyoming:
	Powder River Basin	42,314	—	31,773	—	25,552	—
	Green River Basin	4,167	45	3,165	40	2,044	23
Total		47,401	53	35,514	45	28,019	28

(1)

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

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

		Year Ending December 31,
		2002		2001(1)		2000
State/Basin		Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)
Colorado—Sand Wash Basin		12,624	53	11,693	51	6,658	30
Wyoming:
	Powder River Basin	414,143	—	392,950	7	350,512	—
	Green River Basin	153,897	1,160	65,594	603	51,324	409
Total		580,664	1,213	470,237	661	408,494	439

(1)

On a gas equivalent basis using December 31, 2001 pricing, total proved reserves at December 31, 2001 equates to approximately 476 Bcfe.

        We employ a total staff of 14 full time reservoir and production engineers, geophysicists and geologists who complete annual reserve estimates of reserves connected to each of our existing gathering, processing and treating facilities.

        The report for proved reserves in the Powder River Basin coal bed methane gas and other Wyoming assets for 2002, 2001 and 2000 has been audited by Netherland, Sewell & Associates, Inc.

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

Midstream Operations

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

        On January 31, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. These assets were acquired from El Paso Field Services, EPFS, and related entities. These systems are comprised of a total of 550 miles of gathering lines and, at January 31, 2003, were gathering a total of 139 MMcf per day. Approximately 80% of the revenues to be derived from these facilities will be earned under long-term, fee-based contracts with the remaining revenue generated under keep-whole arrangements. The three largest systems are located near our Red Desert processing facility and will be consolidated into that facility. Four of these systems are located in the Wind River Basin and provide us with the opportunity to expand our gathering and processing activities into an area in which we have not previously operated. Six of the smaller systems are located in the Powder River Basin and will be evaluated for consolidation opportunities or divestiture.

Gas Gathering, Processing and Treating.

        Overall, at December 31, 2002, we operated a total of 17 gathering, processing and treating facilities, or plant operations, with approximately 9,300 miles of gathering lines. These facilities are located in five states and have a combined throughput capacity of 2.9 billion cubic feet, Bcf, per day of natural gas. Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. In 2002, we gathered an average of 1.2 Bcf per day of natural gas, produced natural gas for delivery to markets of 845 MMcf per day and produced 1.8 MMgal per day of NGLs. In addition to our integrated upstream and midstream operations in the Powder River and Green River Basins in Wyoming, our core assets include our plant operations located in west Texas and Oklahoma. We believe that our core assets have stable production rates, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

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

        We acquire dedicated acreage and natural gas supplies in an effort to maintain or increase throughput levels to offset natural production declines of connected wells. We obtain these natural gas supplies by connecting additional wells, purchasing existing systems from third parties and through internally developed projects or joint ventures. Historically, while individual plants have experienced declines in dedicated reserves, we have been successful in connecting additional reserves to more than offset the natural declines. Overall, the level of future drilling will depend upon, among other factors, the prices for gas and oil, the drilling budgets of third-party producers, energy and environmental policy and regulation of governmental agencies and the availability of foreign oil and gas, none of which is within our control. At December 31, 2002, our estimated reserves connected to our midstream facilities totaled 3.6 Tcf. This includes third party reserves connected to our facilities and our proven reserves. In 2002, including the reserves developed by us and associated with our partnerships and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 205% of throughput.

        Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of long-term contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease. Approximately 65% of our plant facilities' gross margins, or revenues at the plants less product purchases, for the month of December 2002 resulted from percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs. We pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. This type of contract allows the producers of the natural gas and us to share proportionally in price changes.

        Approximately 21% of our plant facilities' gross margins for the month of December 2002 resulted from contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling. The proportion of fee-based contracts is expected to increase as the volumes from the Powder River Basin coal bed methane development increase. In addition, the majority of the revenues to be derived from the facilities acquired in January 2003 will be earned under long-term, fee-based contracts.

        Approximately 14% of our plant facilities' gross margins for the month of December 2002 resulted from contracts that combine gathering, compression or processing fees with "keepwhole" arrangements or wellhead purchases. Typically, we charge producers a gathering and compression fee based upon volume. In addition, we retain a predetermined percentage of the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The "keepwhole" component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

        Powder River Basin.     Our midstream operations in the Powder River Basin are fully integrated with our upstream operations. In other words, we provide the gathering, compression and processing services for both our own production and for third-party operators. As of December 31, 2002, our assets in the Powder River Basin in northeast Wyoming were primarily comprised of our coal bed methane gathering system with a capacity of 525 MMcf per day, our 13% equity interest in Fort Union Gas Gathering, L.L.C. with a gross capacity of 635 MMcf per day, and several small gas processing facilities.

        Our capital budget in the Powder River Basin for midstream activities provides for expenditures of approximately $14.7 million during 2003. During 2002, our capital expenditures in this area totaled $19.9 million. We have also entered into several operating leases for compression equipment primarily in the coal bed gathering area. As of December 31, 2002, we had leased a total of 124 compression units and, during 2003 we expect to add an additional 26 compression units to these leases. Depending upon our future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. Due to drilling regulatory, commodity pricing and other uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

        In 1998, we joined with other industry participants to form Fort Union, to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River Basin in northeast Wyoming. We own a 13% equity interest in Fort Union and are the construction manager and field operator. The header delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. The gathering pipeline went into service in 1999 with a capacity of 435 MMcf per day. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by us of approximately $900,000. In 1999, we entered into a ten-year agreement for firm gathering services on 60 MMcf per day of capacity at $0.14 per Mcf on Fort Union. In 2001, a 62-mile expansion of Fort Union was completed and brought the system's capacity to 635 MMcf per day. The expansion costs totaled approximately $22.0 million and were also project financed by Fort Union. In 2001, we invested approximately $500,000 as an equity contribution to Fort Union in conjunction with the project financing. Also in connection with the expansion, we increased our commitment for firm gathering services, effective December 2001, to a total of 83 MMcf per day of capacity at $0.14 per Mcf.

        Green River Basin.     Our midstream operations in the Green River Basin of southwest Wyoming are also fully integrated with our upstream operations in this area. Our midstream assets in this basin are comprised of the Granger and Lincoln Road facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous Gas Services, L.L.C., "Rendezvous," and our Red Desert facility. These facilities have a combined gathering capacity of 465 MMcf per day and a combined processing capacity of 327 MMcf per day. During 2002 these facilities averaged throughput of 348 MMcf per day and processed 198 MMcf per day.

        Our 2003 capital budget for midstream activities in this basin provides for expenditures of approximately $63.9 million during 2003. This capital budget includes approximately $21.2 million for gathering lines and installation of compression to expand the capacity of our Granger Complex, $5.6 million for additional contributions to Rendezvous for the expansion of its system and $37.1 million for the acquisition of 18 additional gathering systems in January 2003. During 2002, our capital expenditures in this area totaled $18.9 million. Due to drilling, commodity pricing and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

        In 2001, we sold a 50% interest in a segment of the gathering system behind our Granger facility, along with associated field compression, to an unrelated third party for $5.2 million. Together, we contributed our respective interests in this system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to a newly formed limited liability corporation named Rendezvous. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. Rendezvous was formed to gather gas along the Pinedale Anticline for blending or processing at either our Granger Complex or at Questar's Blacks Fork processing facility. Rendezvous was expanded during 2001 and 2002 to increase its capacity to 275 MMcf per day. At December 31, 2002, Rendezvous was gathering 190 MMcf per day and we had a total of $22.8 million invested in this venture. A further expansion is proposed for 2003, subject to the necessary approvals, which would extend the system approximately 30 miles further into the Pinedale Anticline at an estimated cost of $10.5 million gross, of which our share is approximately $5.2 million.

        West Texas.     Our primary assets in west Texas are the Midkiff/Benedum complex and the Gomez treating facility. These facilities process gas produced by third parties in the Permian Basin, have a combined operational capacity of 565 MMcf per day and processed an average of 291 MMcf per day in 2002. In 2002, these facilities produced an average of 214 MMcf per day of natural gas for delivery to sales markets and produced an average of 859 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $6.0 million during 2003. This capital budget includes approximately $2.7 million for additions to the gathering systems and plant facilities and approximately $3.3 million for replacing and upgrading field and plant equipment. During 2002, we expended $8.4 million in this area.

        In order to remain competitive with other plant operators in the gathering, processing and treating business, it is important to be a low-cost, efficient operator. Over the past several years, we have invested $29.0 million to replace older compressors at our Midkiff/Benedum complex with fuel-efficient equipment. This upgrade has resulted in lower maintenance costs, reduced emissions and a decrease in our fuel consumption, thereby increasing the natural gas available for sale and our ability to attract additional volumes to our system.

        Oklahoma.     Our primary assets in Oklahoma are the Chaney Dell and Westana systems. These facilities process gas produced by third parties in the Anadarko Basin and have a combined operational capacity of 175 MMcf per day. In 2002, these facilities processed an average of 147 MMcf per day, produced an average of 128 MMcf per day of natural gas for delivery to sales markets and produced 330 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $9.0 million during 2003. This capital budget includes approximately $5.5 million for additions to the gathering systems and plant facilities and approximately $3.5 million for replacing and upgrading field and plant equipment. During 2002, we expended $9.4 million in this area.

        San Juan.     Our assets in the San Juan Basin of New Mexico are the San Juan River processing facility and the Four Corners Gathering system. These facilities gather and process gas produced by third parties in the San Juan and Paradox Basins and have a combined operational capacity of 75 MMcf per day. In 2002, these facilities gathered and processed an average of 27 MMcf per day, produced an average of 23 MMcf per day of natural gas for delivery to sales markets and produced 45 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $1.5 million during 2003. During 2002, we expended $2.4 million in this area.

        Principal Facilities.     The following tables provide information concerning our principal facilities during 2002. We also own and operate several smaller treating, processing and transportation facilities located in the same areas as our other facilities.

						Average for the Year Ended December 31, 2002
				Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcf/D)(3)
Facilities(1)			Year Placed In Service			Gas Throughput (MMcf/D)(4)	Gas Production (MMcf/D)(5)	NGL Production (MGal/D)(5)
Texas
	Gomez Treating(6)		1971	386	280	92	83	—
	Midkiff/Benedum		1949	2,222	165	140	93	858
	Mitchell Puckett Gathering(6)		1972	93	120	59	38	1
Louisiana
	Toca(7)(8)(14)		1958	—	160	50	48	40
Wyoming
	Coal Bed Methane Gathering		1990	1,298	525	379	203	—
	Fort Union Gas Gathering		1999	106	635	453	453	—
	Granger(7)(9)(10)		1987	532	235	200	149	299
	Hilight Complex(7)		1969	626	124	15	10	52
	Kitty/Amos Draw(7)		1969	314	17	7	5	31
	Lincoln Road(10)		1988	149	50	13	12	4
	Newcastle(7)		1981	146	5	3	2	20
	Red Desert(7)		1979	111	42	13	11	22
	Rendezvous Gas Services		2001	—	275	122	122	—
	Reno Junction(9)		1991	—	—	—	—	105
Oklahoma
	Chaney Dell		1966	2,093	130	66	52	325
	Westana		1981	1,017	45	81	76	5
New Mexico
	San Juan River(6)		1955	140	60	25	21	34
Utah
	Four Corners Gathering		1988	104	15	2	2	11
		Total		9,337	2,883	1,720	1,380	1,807

				Average for the Year Ended December 31, 2002
Transportation Facilities(1)		Year Placed In Service	Transportation Miles(2)	Pipeline Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D)(4)
MIGC(11)(13)		1970	245	130	180
MGTC(12)		1963	252	18	12
	Total		497	148	192

Footnotes on following page.

(1)

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

(2)

Gas gathering system miles, transportation miles and pipeline capacity are as of December 31, 2002.

(3)

Gas throughput capacity is as of December 31, 2002 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(4)

Aggregate wellhead natural gas volumes collected by a gathering system or volumes transported by a pipeline.

(5)

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

(6)

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

(7)

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

(8)

Straddle plant, or a plant located near a transportation pipeline that processes gas dedicated to or gathered by a pipeline company or another third-party.

(9)

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

(10)

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

(11)

MIGC is an interstate pipeline located in Wyoming and is regulated by the Federal Energy Regulatory Commission.

(12)

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

(13)

Pipeline capacity represents certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.

(14)

This facility was sold in September 2002.

        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, 1998, involving assets other than those located in the Powder River Basin, Green River Basin, West Texas or Oklahoma which were previously discussed, are:

        Toca Processing Facility.     In June 2002, we entered into an agreement for the sale of our Toca processing facility in Louisiana. This sale closed in September 2002. The sale price was $32.2 million, subject to accounting adjustments, and resulted in a pre-tax loss of approximately $448,000. The purchase price included a natural gas processing plant with a capacity of 160 million cubic feet per day and a fractionator that can separate 14,200 barrels per day of mixed natural gas liquids into propane, normal butane, iso-butane and natural gasoline. The sale also included NGL storage as well as truck, rail and barge loading facilities, which support the complex.

        Bethel Treating Facility.     In 1996 and 1997, the Pinnacle Reef exploration area was rapidly developing into a very active lease acquisition and exploratory drilling area using 3-D seismic technology to identify prospects. The initial discoveries indicated a large potential gas development. Based on our receipt of large acreage dedications in this area, we, through our wholly-owned subsidiary Pinnacle Gas Treating, Inc., constructed the Bethel treating facility for a total cost of approximately $102.8 million. This facility was comprised of a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas.

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

        In 2000, we signed an agreement for the sale of all the outstanding stock of this subsidiary for $38.0 million. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.

        Arkoma.     In August 2000, we sold our Arkoma Gathering System in Oklahoma for gross proceeds of $10.5 million. This sale resulted in a pre-tax gain of $3.9 million.

        Westana.     In February 2000, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million.

        Western Gas Resources-California, Inc.     In January 2000, we sold all of the outstanding stock of our wholly owned subsidiary, Western Gas Resources-California, Inc., or WGR-California, for $14.9 million. The only asset of this subsidiary was a 162-mile pipeline in the Sacramento Basin of California. 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 2000.

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

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

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

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

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

Transportation.

        We own and operate MIGC, Inc. an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, Inc. an intrastate pipeline located in northeast Wyoming. MIGC charges a Federal Energy Regulatory Commission, FERC, approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC. During 2002, MIGC transported an average of 180 MMcf per day. It is anticipated that MIGC will continue to operate around that level through 2003. MIGC earns fees on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. Contracts for firm capacity on MIGC range in duration from one month to six years and the fees charged average $0.33 per Mcf.

        The FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies. In addition, the FERC has proposed to limit the use of affiliates' employees in the operation of regulated entities. In August 2002, the FERC issued a Notice of Proposed Rule Making that, if enacted, would require MIGC to establish its own cash management function, including its own revolving credit facility, and would limit the ability of MIGC to transfer funds to us. Further, this proposed rule may require us to modify our existing subsidiary guarantees under our debt agreements. We can make no assurances as to the ultimate regulations passed by the FERC or the effects such regulations may have on the operating costs of MIGC or our financial position.

        MGTC provides transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and Wright at rates that are subject to the approval of the Wyoming Public Service Commission. During 2002, MGTC transported an average of 12 MMcf per day and sold an average of 1 MMcf per day.

Marketing.

        Gas.     We market gas produced at our wells and our plants and purchased from third parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. In addition to our offices in Denver, we have marketing offices in Houston, Texas and Calgary, Alberta. Historically, our gas marketing was an outgrowth of our gas processing activities and was directed toward selling gas processed at our plants to ensure their efficient operation. As the natural gas industry became deregulated and offered more opportunity, we increased our third-party gas marketing. 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. For the year ended December 31, 2002, our total gas sales volumes averaged 2.0 Bcf per day, of which 447 MMcf per day was produced at our plants or from our producing properties.

        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. For example, during 2002, as a result of limited pipeline capacity from the Rocky Mountain region to market centers in the mid-continent and west coast areas, natural gas in this region has sold at a substantial discount to these other market areas. We had commodity price hedges and firm transportation capacity to the mid-continent markets on approximately 92% of our equity production in the Rocky Mountain area for 2002. This allowed us to realize an approximate $0.90 per Mcf improvement in price for natural gas per MMbtu relative to what would have been received if these hedges and capacity rights had not existed. We have similar hedges and transportation positions for approximately 99% of estimated 2003 equity production of natural gas in the Rocky Mountain region.

        We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. The average duration as of December 31, 2002 of our sales contracts was 15 months. The marketing of products purchased from third parties typically results in low operating margins relative to the sales price. Revenues for sales of product are recognized at the time the gas is delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. We record revenue on our physical gas marketing activities on a gross basis versus sales net of purchases basis. We believe that this presentation is required because we obtain title to all the gas that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions and it is our intention upon entering these contracts to take physical delivery of the natural gas. Gains and losses on any accompanying financial transactions are recorded net. Additionally, for our marketing activities, we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods. During the year ended December 31, 2002, we sold gas to approximately 255 end-users, pipelines, LDCs and other customers. Two customers accounted for approximately 10% of our consolidated revenues from the sale of gas, or 9% of total consolidated revenue, for the year ended December 31, 2002. One of these customers is an energy merchant and the other customer is an electric utility. We are not currently entering into new transactions with the energy merchant. In general, we do not expect to increase our third-party sales volumes in 2003 significantly from levels achieved over the last several years, and in fact, due to price volatility and credit concerns in the energy industry, our overall sales volumes may decrease.

        NGLs.     We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. For the year ended December 31, 2002, NGL sales averaged 2,010 MGal per day, of which 1,417 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 products. Over the last several years, the petrochemical industry has increased its use of NGLs as a major feedstock and is projected to continue to increase such usage. Further, consumers use propane for home heating, transportation and agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

        We decreased NGL sales to third parties by approximately 340 MGal per day in the year ended December 31, 2002 compared to 2001. With the sale of our Toca facility in September 2002, we anticipate that sales of third-party product will decrease further. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counter parties.

        During the year ended December 31, 2002, we sold NGLs to 102 customers including end-users, fractionators, chemical companies and others. Three customers accounted for approximately 38% of our consolidated revenues from the sale of NGLs, or 5% of total consolidated revenue, for the year ended December 31, 2002. One of these customers is a large integrated energy company, another is a large petrochemical company and the third is an energy merchant. We are not currently entering into new transactions with the energy merchant. We also derive revenues from contractual marketing fees charged to some producers for NGL marketing services. For the year ended December 31, 2002, these fees were less than 1% of our consolidated revenues.

        We sell NGLs under agreements with varying terms and conditions in order to match seasonal and other changes in demand. As of December 31, 2002, the terms of our sales contracts range from one month to five years. The marketing of products purchased from third parties typically results in low operating margins relative to the sales price. Revenues for sales of NGLs are recognized at the time the NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. We record revenue on our physical NGL marketing activities on a gross sales versus sales net of purchases basis. We believe that this presentation is required because we obtain title to all the NGLs that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions and it is our intention upon entering these contracts to take physical delivery of the product. Gains and losses on any accompanying financial transactions are recorded net. Additionally, for our marketing activities we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

Environmental

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

        Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the gathering systems acquired from EPFS, in January 2003, we identified many well sites that include underground sump tanks, pits, or tinhorns that are not properly permitted according to Wyoming Oil and Gas Conservation Commission, or WYOGCC, regulations. We have reported these violations to WYOGCC and are providing it with our remediation plan. It is our intention to remove all these underground facilities over the next several months. Based on our discussions with WYOGCC, it is our belief that it will not pursue any type of fines or penalties from us related to these assets. We believe the cost of our remediation plan will approximate $1.5 million, and EPFS has established an escrow account in that amount to reimburse us for these and other costs. In addition, at the time of the acquisition, we obtained an insurance policy that we believe will cover any additional environmental issues that may be identified over the next three years associated with these assets, up to a total exposure of $5.0 million.

        The Texas Council on Environmental Quality, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to it regarding a voluntary emissions reduction plan for the permitting of existing "grand-fathered" air emissions sources within Texas. A "grand-fathered" air emissions source is one that does not need a state operating permit because it was constructed prior to 1971. We operate a number of these sources within Texas, including portions of our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a modernization program, which was completed in March 2002, we replaced the majority of our "grand- fathered" equipment in Texas. We believe that the potential cost of complying with these regulations for our remaining "grand-fathered" equipment will not have material effect on our results of operations or financial position.

        We anticipate that the trend in environmental legislation and regulation will continue to be toward stricter standards. Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required. We are evaluating all our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements. We currently estimate our costs for compliance to be approximately $2.0 million. The new spill prevention plans must be in place for covered assets by April 2003. All modifications called for in those plans must be in place by August 2003. We are unaware of any other future environmental standards that are reasonably likely to be adopted that will have a material effect on our financial position or results of operations, but we cannot rule out that possibility.

        We are in the process of voluntarily cleaning up substances at certain facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $1.4 million for the year ended December 31, 2002, including approximately $587,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material effect on our financial position or results of operations.

Competition

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

Regulation

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

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

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

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

Employees

        At December 31, 2002, we employed 636 full-time employees, of which 371 were employed at field locations. None of our employees is a union member. We consider relations with employees to be excellent.

ITEM 3. LEGAL PROCEEDINGS

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

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

        There were no matters submitted to a vote of security holders during the quarter ended December 31, 2002.

PART II

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

        As of March 3, 2003, there were 33,099,577 shares of common stock outstanding held by 198 holders of record. The common stock is traded on the New York Stock Exchange, or NYSE, under the symbol "WGR". The following table sets forth quarterly high and low sales prices as reported by the NYSE Composite Tape for the quarterly periods indicated.

	HIGH		LOW
2002
Fourth Quarter	$	38.00	$	30.35
Third Quarter		37.54		25.00
Second Quarter		40.12		35.24
First Quarter		37.50		28.22
2001
Fourth Quarter	$	35.65	$	26.08
Third Quarter		33.59		24.88
Second Quarter		43.50		31.64
First Quarter		33.70		25.33

        We paid annual dividends on our common stock aggregating $0.20 per share during the years ended December 31, 2002 and 2001. We have declared a dividend of $0.05 per share of common stock for the quarter ending March 31, 2003 to holders of record as of March 28, 2003. Declarations of dividends on our common stock are within the discretion of the board of directors. In addition, our ability to pay dividends on our common stock is restricted by covenants in our financing facilities, the most restrictive of which is in our subordinated note indenture and that covenant prohibits declaring or paying dividends that exceed, in the aggregate, the sum of $20 million plus 50% of our consolidated net operating income (as defined in the indenture) earned after July 1, 1999 (or minus 100% if a net loss) plus the aggregate net cash proceeds received after July 1, 1999 from the sale of any stock. At December 31, 2002, availability under this covenant was approximately $42.8 million.

Equity Compensation Plan Information

        The following table summarizes our equity compensation plans under which securities may be issued as of December 31, 2002. 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.

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	1,051,812	$	28.67	1,154,003
Equity compensation plans not approved by security holders	308,350	$	24.48	—
Total	1,360,162	$	27.72	1,154,003

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

        1999 Non-Employee Directors Stock Option Plan.     Effective March 1999, our board of directors adopted a stock option plan that authorized the granting of options to purchase 15,000 shares of our common stock to non-employee directors. During 1999, the board approved grants of options covering a total of 15,000 shares of our common stock to several board members. The exercise price of the stock underlying each option was the average closing price of our common stock 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 his employment agreement, dated October 15, 2001, and the stock option agreement, dated as of November 1, 2001, between us and Peter A. Dea, our CEO and President, we granted non-qualified stock options to Mr. Dea for the purchase of 300,000 shares of our common stock. The exercise price of the options was equal to $5.00 below the closing price per share on the effective date of his employment agreement. The stock options are subject to the conditions of the agreements and vest equally over four years and must be exercised within five years of the date on which the option vests. The difference between the closing price on the effective date and the exercise price is being amortized over four years as compensation expense.

ITEM 6. SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated historical financial and operating data for Western. Certain prior year amounts have been reclassified to conform to the presentation used in 2002. The data for the three years ended December 31, 2002, 2001 and 2000 should be read in conjunction with our Consolidated Financial Statements and the notes thereto included elsewhere in this Form 10-K. The selected consolidated financial data for the years ended December 31, 1999 and 1998 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."

	Year Ended December 31,
	2002			2001			2000			1999			1998
	(000s, except per share amounts and operating data)
Statement of Operations:
Revenues	$	2,489,698		$	3,353,162		$	3,280,091		$	1,909,288		$	2,115,995
Gross profit(a)		144,430			200,780			149,155			67,289			50,090
Income (loss) before income taxes		80,703			152,126			91,384			(25,184	)(b)		(105,623	)(b)
Provision (benefit) for income taxes		30,114			56,489			33,562			(9,167	)		(38,418	)
Income (loss) before extraordinary items		50,589			95,637			57,822			(16,017	)(b)		(67,205	)(b)
Extraordinary charge for early extinguishment of debt		—			—			(1,714	)(c)		(1,107	)(c)		—
Net income (loss)		50,589			95,637			56,108			(17,124	)(b)		(67,205	)(b)
Earnings (loss) per share of common stock		1.26			2.59			1.42			(.86	)		(2.42	)
Earnings (loss) per share of common stock—assuming dilution		1.23			2.48			1.39			(.86	)		(2.42	)
Other financial data:
Net cash provided by operating activities		131,136			153,267			116,262			95,184			(35,570	)
Net cash provided by (used in) investing activities		(105,772	)		(131,657	)		(82,039	)		67,284			(26,441	)
Net cash provided by (used in) financing activities		(28,084	)		(24,506	)		(35,358	)		(152,806	)		46,634
Capital expenditures		125,600			163,977			108,536			80,089			105,216
Balance Sheet Data (at year end):
Total assets		1,302,144			1,267,942			1,431,422			1,049,486			1,219,377
Long-term debt		359,933			366,667			358,700			378,250			504,881
Stockholders' equity		483,068			473,352			391,534			349,743			385,216
Dividends on preferred stock		9,198			11,167			10,416			10,439			10,439
Dividends on common stock		6,603			6,524			6,448			6,426			6,430
Dividends per share of common stock		.20			.20			.20			.20			.20
Operating Data:
Average gas sales (MMcf/D)		1,988			1,961			1,835			1,900			2,200
Average NGL sales (MGal/D)		2,010			2,347			3,085			2,885			4,730
Average gas volumes gathered (MMcf/D)		1,163			1,161			1,248			1,168			1,162
Facility capacity (MMcf/D)		2,581			2,574			2,374			2,485			2,237
Average gas prices ($/Mcf)	$	2.92		$	3.97		$	3.90		$	2.17		$	2.01
Average NGL prices ($/Gal)	$	.42		$	.49		$	.52		$	.33		$	.26

(a)

Excludes selling and administrative, interest, restructuring and income tax expenses, expenses for the impairment of property and equipment, (gains) or losses on sales of assets, and any extraordinary items. See further discussion in notes (b), (c) and (d).

(b)

Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," or SFAS No. 121, required that an impairment loss be recognized when the carrying amount of an asset exceeds its fair market value or the expected future undiscounted net cash flows. In accordance with SFAS No. 121, we recognized a pre-tax, non-cash loss on the impairment of property and equipment of $1.2 million, or $0.7 million after-tax, and $108.5 million, or $69.0 million after-tax, for the years ended December 31, 1999 and 1998, respectively.

(c)

We recognized an after-tax extraordinary charge on the early extinguishment of long-term debt in 2000 and in 1999 of $1.7 million and $1.1 million, respectively.

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, 2002, 2001 and 2000. Certain prior year amounts have been reclassified to conform to the presentation used in 2002. Reference should also be made to our Consolidated Financial Statements and related Notes thereto and the Selected Financial Data included elsewhere in this Form 10-K.

Results of Operations

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

	Year Ended December 31,
					Percent Change
	2002		2001
Financial results:
Revenues	$	2,489,698	$	3,353,162	(26	)
Gross profit		144,430		200,780	(28	)
Net income (loss)		50,589		95,637	(47	)
Income (loss) per share of common stock		1.26		2.59	(51	)
Income (loss) per share of common stock—assuming dilution		1.23		2.48	(50	)
Net cash provided by operating activities	$	131,136	$	153,267	(14	)
Operating data:
Average gas sales (MMcf/D)		1,988		1,961	1
Average NGL sales (MGal/D)		2,010		2,347	(14	)
Average gas prices ($/Mcf)	$	2.92	$	3.97	(26	)
Average NGL prices ($/Gal)	$	.42	$	.49	(14	)

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

        Revenues from the sale of gas decreased $725.6 million to $2.1 billion for the year ended December 31, 2002 compared to 2001. This decrease was primarily due to a decline in product prices, which more than offset an increase in sales volume in the year ended December 31, 2002. Average gas prices realized by us decreased $1.05 per Mcf to $2.92 per Mcf in the year ended December 31, 2002 compared to 2001. Included in the realized gas price were approximately $28.7 million of gains recognized in the year ended December 31, 2002 related to futures positions on equity gas volumes. We have entered into additional futures positions for the majority of our equity gas for 2003. See further discussion in "Item 7A. Quantitative and Qualitative Disclosures About Market Risk". Average gas sales volumes increased minimally to 1,988 MMcf per day in the year ended December 31, 2002 compared to 2001.

        On June 5, 2002, and as amended on June 18, 2002, we responded to a data request of the FERC in Docket No. PA02-2-000. The FERC's request inquired as to any "wash", "round trip", or "sell, buy back" trading in the United States portion of the Western States Coordinating Council and/or Texas during the years ended December 31, 2000 and 2001. During this time period, we engaged in two transactions that met the FERC's criteria for a transaction of this type. The transactions occurred in April 2001 and involved an aggregate quantity of approximately 259,000 MMbtu or $3.5 million of gross revenue. The transactions were not entered into for the purpose of artificially inflating our sales volume or revenue. Our internal control policies require valuation of the current market value of gas placed in storage based upon objective criteria, and these transactions were intended to provide a third-party generated price for natural gas placed in storage. These transactions represented 0.1% of our total sales revenues for the year ended December 31, 2001. The FERC has not inquired as to sales activity in 2002. However, during 2002, no transactions of this type are included in our revenues.

        Revenues from the sale of NGLs decreased approximately $114.4 million to $309.7 million in the year ended December 31, 2002 compared to 2001. This decrease is due to a reduction in product prices and to a reduction in sales volume. Average NGL prices realized by us decreased $0.07 per gallon to $0.42 per gallon in the year ended December 31, 2002 compared to 2001. Included in the realized NGL price were approximately $8.5 million of losses recognized in the year ended December 31, 2002 related to futures positions on equity NGL volumes. We have entered into additional futures positions for a portion of our equity NGL production for 2003. See further discussion in "Item 7A. Quantitative and Qualitative Disclosures About Market Risk". Average NGL sales volumes decreased 337 MGal per day to 2,010 MGal per day in the year ended December 31, 2002 compared to 2001.

        Product purchases decreased by $829.8 million for the year ended December 31, 2002 compared to 2001 primarily as a result of the decrease in commodity prices. Overall, combined product purchases as a percentage of sales of all products decreased to 89% for the year ended December 31, 2002 from 92% for 2001. The decrease in the product purchase percentage for the year ended December 31, 2002 versus 2001 resulted from a decrease in product prices and an increase of sale of our production from the Powder River Basin development.

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

        Marketing margins on NGLs averaged approximately $0.008 per gallon in the year ended December 31, 2002. This represents an increase as compared to the $0.005 per gallon realized in 2001. This is due to more favorable market conditions that were present in 2002 as compared to 2001.

        In the year ended December 31, 2002, we expensed a total of $1.6 million for doubtful accounts, primarily due to the bankruptcy filing of a large mid-western co-op during the year. This compares to an expense of $2.7 million for doubtful accounts in 2001. These charges are not included in the calculation of the marketing margins and are reported in Selling and administrative expenses.

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

        Oil and gas exploration and production expenses increased by $6.5 million in the year ended December 31, 2002 as compared to 2001. In our operating areas, the significant reduction in residue gas prices in the 2002 periods resulted in substantially lower severance tax expenses. These reductions were substantially offset by increased lease operating expenses, or LOE, in the Powder River Basin coal bed development. Overall, LOE averaged $0.42 per Mcf in the year ended December 31, 2002. LOE in the Powder River Basin coal bed development averaged $0.45 per Mcf in the year ended December 31, 2002. This represents increases of $0.06 per Mcf and $0.09 per Mcf from the comparable periods in 2001, respectively. The increases are substantially due to higher utility charges, increased use of leased generators, increased labor charges and prior period adjustments for operating supplies, utilities and technical supervision billed to us by the well operator. The increased LOE in 2002 were substantially offset by lower severance taxes resulting from the significant reduction in residue gas prices in 2002 as compared to 2001.

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

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

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

Cash Flow Information

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

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

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

Other Information

        Preferred Stock Redemption.     In December 2002, we redeemed all the remaining shares of our $2.28 cumulative preferred stock currently outstanding, at a liquidation preference of $25.00 per share plus accrued and unpaid dividends, for a total of approximately $14.0 million. The capitalized offering costs of $688,000 associated with the redeemed preferred stock are reflected as a special dividend to preferred shareholders in 2002 and reduced earnings available to common shareholders by approximately $0.02 per common share.

        Toca Processing Facility.     In June 2002, we entered into an agreement for the sale of our Toca processing facility in Louisiana. This sale closed in September 2002. The sale price was $32.2 million, subject to accounting adjustments, and resulted in a pre-tax loss of approximately $448,000. The purchase price included a natural gas processing plant with a capacity of 160 million cubic feet per day and a fractionator that can separate 14,200 barrels per day of mixed natural gas liquids into propane, normal butane, iso-butane and natural gasoline. The sale also includes NGL storage as well as truck, rail and barge loading facilities, which support the complex. During the year ended December 31, 2002, this facility generated net after-tax earnings of approximately $683,000, or $.02 per share of common stock, respectively. We believe the results from this facility are immaterial for separate presentation as a discontinued operation. Approximately $15.0 million of the proceeds received from this asset sale were initially used to reduce amounts outstanding on our Revolving Credit Facility. At December 31, 2002, the remaining amount of $17.2 million was on deposit with a trustee in anticipation of the completion of a like-kind exchange transaction and was reflected on the Consolidated Balance Sheet under the caption Other current assets. These funds, along with additional amounts drawn on our Revolving Credit Facility, were used in a January 2003 acquisition of several gathering systems.

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

        Transactions with Officers.     In October 2002, we granted options covering a total of 169,500 shares of our common stock to our ten executive officers. The exercise price with respect to these options is $32.95 per share. In accordance with the terms of the stock option plan pursuant to which the options were granted, the option price is the average closing price for our common stock for the ten trading days prior to the grant.

        In June 2001, the Compensation and Nominating Committee recommended, and the board approved, retention bonuses totaling $820,000 for nine of our executive officers. These bonuses were contingent upon the officer not voluntarily terminating employment for one year following the hiring of a new Chief Executive Officer and President. These bonuses were paid on November 1, 2002.

        In 1989, we loaned to our officers at that time, an amount sufficient to exercise their options under our stock option plans. The loans and accrued interest were to be forgiven if the officer remained employed by us for specified time periods and upon a resolution of the board of directors. During 2002, we forgave loans totaling $703,000 related to the exercise of options covering 62,500 shares of common stock. After giving effect to the forgiveness, a loan in the amount of $134,000 related to the exercise of options covering 12,500 shares of common stock remains outstanding. Pursuant to the terms of an agreement entered into in the second quarter of 2001, the remaining loan will be forgiven in May 2003. In prior years, we have reserved for the forgiveness of these loans.

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

	Year Ended December 31,
					Percent Change
	2001		2000
Financial results:
Revenues	$	3,353,162	$	3,280,091	2
Gross profit		200,780		149,155	35
Net income (loss)		95,637		56,108	70
Income (loss) per share of common stock		2.59		1.42	82
Income (loss) per share of common stock—assuming dilution		2.48		1.39	78
Net cash provided by operating activities	$	153,267	$	116,262	32
Operating data:
Average gas sales (MMcf/D)		1,961		1,835	7
Average NGL sales (MGal/D)		2,347		3,085	(24	)
Average gas prices ($/Mcf)	$	3.97	$	3.90	2
Average NGL prices ($/Gal)	$	.49	$	.52	(6	)

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

        Revenues from the sale of gas increased $221.0 million to $2,849.1 million in the year ended December 31, 2001 compared to 2000. This increase was primarily due to an improvement in product prices and to a lesser extent from an increase in sales of natural gas purchased from third parties. Average gas prices realized by us increased $0.07 per Mcf to $3.97 per Mcf in the year ended December 31, 2001 compared to 2000. Included in the realized gas price were approximately $9.3 million of gains recognized in the year ended December 31, 2001 related to futures positions on equity gas volumes. Average gas sales volumes increased 125 MMcf per day to 1,960 MMcf per day in the year ended December 31, 2001compared to 2000. This increase in sales volume was primarily due to an increase in the sale of third- party product.

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

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

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

        Marketing margins on NGLs averaged approximately $0.005 per gallon in the year ended December 31, 2001. This represents a decrease as compared to the margin realized during 2000 of $0.007 per gallon. This decrease has resulted in our decision to intentionally reduce the sale of third-party NGL products.

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

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

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

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

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

Other Information

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

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

        Arkoma.     In August 2000, we sold our Arkoma Gathering System in Oklahoma for gross proceeds of $10.5 million. This sale resulted in a pre-tax gain of $3.9 million.

        Western Gas Resources-California, Inc.     In January 2000, we sold all the outstanding stock of our wholly owned subsidiary, WGR-California, for $14.9 million. The only asset of this subsidiary was a 162-mile pipeline in the Sacramento Basin of California. 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 the first quarter of 2000.

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

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

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

        Also in October 2001, both Questar and Western contributed their respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to a newly formed joint venture named Rendezvous. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. Our 50% interest in Rendezvous is accounted for under the equity method.

Critical Accounting Policies

        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. Our critical accounting policies and estimates are discussed below. For further details on our accounting policies, and the estimates, assumptions and judgments we use in applying these policies and a discussion of new accounting rules, see Note 2 of the Notes to Consolidated Financial Statements.

        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.

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

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

        Oil and Gas Properties and Equipment.     We follow the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized when incurred. Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves. The unit of production method is sensitive to the determination of proved reserves. We utilize technical analysis and outside expertise annually to determine the reserves associated with our oil and gas properties. To the extent the reserves are modified based on this review, the depletion determined under the units of production method will be increased or decreased on a prospective basis.

        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. This review is completed at the plant facility, the related group of plant facilities or the oil and gas producing property level. In order to determine whether an impairment exists, we compare the net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. This analysis is sensitive to, among other things, management's expectation of commodity prices, operating costs, drilling plans and production rates.

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

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

        Recently Issued Accounting Pronouncements.     We continually monitor and revise our accounting policies as new rules are issued. At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which will have an impact on our accounting when these rules become effective in 2003. See further discussion in Note 2—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

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 Green River Basins in Wyoming and our midstream operations in west Texas and Oklahoma. Our long-term business plan is to increase shareholder value by: (i) doubling proven reserves and equity production of natural gas from the levels achieved in 2001 over a three to five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

Liquidity and Capital Resources

        Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek alternative financing sources. Product prices, sales of inventory, the volumes of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables will all affect future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, 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, although some of our plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines. During 2002, some producers in the Rocky Mountain region have curtailed existing production or delayed their drilling programs due to lower prices resulting from limited transportation capacity out of the region. The overall level of drilling 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 availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities. Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third parties and us. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A reduction in any of these activities could have a material adverse effect on our financial condition and results of operations.

        We believe that the amounts available to be borrowed under the Revolving Credit Facility, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities, complete our current capital expenditure program and make any scheduled debt principal payments through 2003. We have from time to time renegotiated the Revolving Credit Facility to extend the maturities of the facility, and we intend to re-syndicate this facility and extend its maturity during the first quarter of 2003. This new facility will reflect the current bank market and will likely result in a higher interest rate. Depending on the timing and the amount of our future projects, and our ability to renegotiate the facility, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We also believe that cash provided by operating activities and amounts available under the Revolving Credit Facility will be sufficient to meet scheduled principal repayments during 2003 of $43.3 million under the Master Shelf Agreement and our preferred stock dividend requirements during 2003 of approximately $7.2 million.

        We have effective shelf registration statements filed with the SEC for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock. These shelf registrations allow us to access the debt and equity markets without the requirement of further SEC review.

        Our sources and uses of funds for the year ended December 31, 2002 are summarized as follows (dollars in thousands):

Sources of funds:
	Borrowings under the Revolving Credit Facility		$	994,545
	Proceeds from the dispositions of property and equipment			34,865
	Net cash provided by operating activities			131,136
	Proceeds from exercise of common stock options			6,489
		Total sources of funds	$	1,167,035
Uses of funds:
	Payments related to long-term debt (including debt issue costs)		$	1,001,404
	Capital expenditures			125,600
	Preferred dividends paid			8,504
	Common dividends paid			6,603
	Redemption of $2.28 Cumulative Perpetual Preferred Stock			12,607
	Contributions to equity investees			15,037
	Total uses of funds		$	1,169,755

        Capital Investment Program.     Our capital expenditures totaled approximately $140.6 million during 2002 with approximately 80% invested in the Rocky Mountain region. Overall, capital expenditures in 2002 consisted of the following: (i) approximately $60.0 million related to gathering, processing, treating and pipeline assets, including $7.4 million for maintaining existing facilities; (ii) approximately $70.7 million related to exploration and production and lease acquisition activities; (iii) approximately $4.0 million for information technology; and (iv) approximately $5.9 million for capitalized overhead and interest. Overall, capital expenditures in the Powder River Basin coal bed methane development and in the Green River Basin in southwest Wyoming operations represented 57% and 20%, respectively, of the total capital expenditures in 2002.

        In 2003, we anticipate capital expenditures of approximately $182.3 million. Overall, the 2003 capital budget consists of the following: (i) approximately $58.2 million related to gathering, processing, treating and pipeline assets, including $11.4 million for maintaining existing facilities; (ii) approximately $74.9 million related to exploration and production and lease acquisition activities; (iii) $37.1 million for the acquisition of 18 gathering systems which closed in January 2003; (iv) approximately $4.3 million for information technology and other items and (v) $7.8 million for capitalized interest and overhead. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 37% and 45%, respectively, of the total 2003 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2003 will not change. We anticipate that funds for the 2003 capital budget will be provided primarily by internally generated cash flow, from the proceeds from the sale of our Toca facility in the fourth quarter of 2002 and from amounts available under our Revolving Credit Facility. This budget may be further increased to provide for acquisitions if approved by our board of directors.

Contractual Commitments and Obligations

        Contractual Cash Obligations.     A summary of our contractual cash obligations as of December 31, 2002 is as follows (dollars in thousands):

			Payments by Period
Type of Obligation	Total Obligation		Due in 2003		Due in 2004 - 2005		Due in 2006 - 2007		Due Thereafter
Guarantee of Fort Union Project Financing	$	6,302	$	478	$	1,059	$	1,224	$	3,541
Operating Leases		61,686		12,902		18,884		16,874		13,026
Firm Transportation Capacity and Gathering Agreements		258,615		30,652		58,394		56,988		112,581
Firm Storage Capacity Agreements		28,633		5,240		7,577		5,365		10,451
Long-term Debt		359,934		43,334		141,600		20,000		155,000
Total Contractual Cash Obligations	$	715,170	$	92,606	$	227,514	$	100,451	$	294,599

        Guarantee of Fort Union Project Financing.     In 1998, we joined with other industry participants to form Fort Union to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River Basin in northeast Wyoming. We own a 13% equity interest in Fort Union and are the construction manager and field operator. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by us of approximately $900,000. In 2001, an expansion of Fort Union was completed. The expansion costs totaled approximately $22.0 million and were also project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. In 2001, we invested approximately $500,000 as an equity contribution to Fort Union in conjunction with the project financing. All participants in Fort Union have guaranteed Fort Union's payment of the project financing on a proportional basis, resulting in our guarantee of $6.3 million of the debt of Fort Union at December 31, 2002. This guarantee is not reflected on our Consolidated Balance Sheet.

        Operating Leases.     In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, primarily to support our growing development in the Powder River coal bed development, we have entered into operating leases for compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. As of December 31, 2002, we had leased a total of 124 compression units. These leases have terms ranging from two to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the early buyout options on all leased equipment, these purchase options would require the capital expenditure of approximately $32.6 million between the years of 2007 and 2011. At December 31, 2002, we had four compressor units under an interim leasing agreement. These compressors will be added to the existing lease arrangements when the equipment is installed and in service.

        In August 2002, we entered into a seven year and nine month agreement for the lease of approximately 85,000 square feet of office space in Denver, Colorado. The cumulative lease payments over the term of this agreement, which begins upon occupancy, will total approximately $10.7 million. Our corporate offices were relocated to this space in March 2003. We also entered into a ten-year agreement effective in January 2003 for the lease of approximately 26,000 square feet of office space in Gillette, Wyoming for our Wyoming field operations. The cumulative lease payments over the term of this agreement will total approximately $3.0 million. Neither of these leases is included in the table presented above since neither was in effect at December 31, 2002.

        Firm Transportation Capacity and Gathering Agreements.     Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. As of December 31, 2002, we had contracts for approximately 674 MMcf per day of firm transportation. This amount represents our total contracted amount on many individual pipelines. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 173 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 408 MMcf per day of firm capacity on four separate pipelines. The total rate to transport this gas to the Mid-Continent approximates $0.35 per Mcf. Our remaining firm capacity consists of 146 MMcf per day to markets within the Rocky Mountains and 120 MMcf per day contracted in various other markets throughout the country. In addition, we hold 83 MMcf per day of firm gathering capacity on the Fort Union gathering line.

        A portion of this firm transportation capacity was contracted for use in our Marketing operations. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 56 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During 2002, these types of transactions have been profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. Historically, to the extent these transportation contracts were acquired for our Marketing segment, they were derivative contracts as defined by SFAS No. 133 and are marked to market. On October 1, 2002, the FERC's policy on capacity release expired. After that date, companies are no longer able to re-market transportation capacity at rates which exceed the maximum allowable rate permitted by the pipelines' tariff. On some pipelines, this reduces our ability to liquidate our position. Accordingly, the transportation contracts on these specific pipelines are no longer considered derivatives under SFAS No. 133 and will not be marked to market. On occasion we may elect to hedge the cash flows resulting from transactions utilizing this transportation capacity. To the extent of these hedges the transactions are classified as cash flow hedges.

        We expect that the fixed fees associated with our contracts for firm transportation capacity during 2003 will average approximately $0.16 per Mcf per day. The associated contract periods range from one month to fourteen years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

        Firm Storage Capacity Agreements.     We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of December 31, 2002, we had contracts in place for approximately 20.2 Bcf of storage capacity at various third-party facilities. The fees associated with these contracts during 2003 will average $0.29 per Mcf of annual capacity. The associated contract periods have an average term of seventeen months. At December 31, 2002, we held gas in our contracted storage facilities and in imbalances of approximately 15.1 Bcf at an average cost of $2.72 per Mcf compared to 16.9 Bcf at an average cost of $2.39 per Mcf at December 31, 2001. These positions are for storage withdrawals within the next fifteen months. At the time that 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. We have also entered into a precedent agreement for 2.4 Bcf of annual capacity, for a term of ten years, for storage in a facility, which is not yet completed. We anticipate the completion of the construction of this facility in 2004. When the facility is completed, we will enter into a storage agreement.

        From time to time, we lease NGL storage space at major trading locations in order to store products for resale during periods when prices are favorable and to facilitate the distribution of products. At December 31, 2002, we held NGLs in storage at various third-party facilities of 2,755 MGal, consisting primarily of propane and normal butane, at an average cost of $0.25 per gallon compared to 5,665 MGal at an average cost of $0.33 per gallon at December 31, 2001.

Long-term Debt

        Revolving Credit Facility.     The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, which matures on April 24, 2003, and a $167 million Revolving Credit Facility, or Tranche B, which matures on March 31, 2004. At December 31, 2002, $96.6 million was outstanding under this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. We have the option to determine which rate will be used. We also pay a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on our debt to capitalization ratio and range from .75% to 2.00%. At December 31, 2002, the interest rate payable on borrowings under this facility was approximately 2.6%. We are required to maintain a total debt to capitalization ratio of not more than 55%, and a senior debt to capitalization ratio of not more than 35%. The agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest and dividends on preferred stock for the same period. This ratio must exceed 3.25 to 1.0. This facility also limits our ability to enter into operating leases and sale-leaseback transactions. This facility is guaranteed and secured via a pledge of the stock of all of our material subsidiaries.

        We intend to enter into a new revolving loan arrangement in the first quarter of 2003 to replace the existing Revolving Credit Facility. Our practice has been to replace our existing facility approximately one year prior to its final maturity date to ensure adequate sources of capital for our operations. As proposed, this new facility will reflect the current bank market with the interest rate spreads and facility fee adjusted based on our debt to capitalization ratio and ranging from 1.50% to 2.25%. While we believe that we will be able to secure a new revolving loan agreement, we can provide no assurance as to the pricing, terms and covenants of this new agreement.

        Master Shelf Agreement.     In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31, 2002 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	8,333	7.99	%	October 27, 2003	single payment at maturity
December 27, 1993		25,000	7.23	%	December 27, 2003	single payment at maturity
October 27, 1994		25,000	9.24	%	October 27, 2004	single payment at maturity
July 28, 1995		50,000	7.61	%	July 28, 2007	$10,000 on each of July 28, 2003 through 2007
	$	108,333

        Under our agreement with Prudential, we are required to maintain a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 35%. This agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest for the same period. This ratio must exceed 3.25 to 1.0. The agreement also provides for a maximum ratio of senior debt to EBITDA of 4.0 to 1.0. In addition, this agreement contains a calculation limiting dividends and other restricted payments including preferred stock redemptions. Under this limitation, approximately $78.3 million was available for restricted payments at December 31, 2002. This facility also limits our ability to enter into operating leases and sale-leaseback transactions. The agreement provides for an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement if we have not received an implied investment grade rating on our senior unsecured debt from Moody's Investors Service or Standard & Poor's and if the ratio of adjusted consolidated debt to EBITDA (as defined in the shelf) for the period of four fiscal quarters most recently ended exceeds 3.00 to 1.0. Under these terms, this fee is not currently being assessed. Borrowings under the Master Shelf Agreement are guaranteed by, and secured via, a pledge of the stock of all of our material subsidiaries.

        In October 2002, we funded a required principal repayment under the Master Shelf Agreement of $8.3 million with funds available under the Revolving Credit Facility. During 2003, we are required to make principal payments totaling $43.3 million. We intend to fund these with amounts available under the Revolving Credit Facility.

        On January 17, 2003, we borrowed an additional $25.0 million under the Master Shelf Agreement. The note bears interest at 6.36% and will be due in a single payment on January 18, 2008. We have the option to prepay the amount in full, at par on January 18, 2005. The funds we received from this borrowing were used in connection with our acquisition of 18 gathering systems in January 2003.

        Senior Subordinated Notes.     In 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradeable notes under the same terms and conditions. The Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain covenants, which include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends and preferred stock redemptions, approximately $42.8 million was available at December 31, 2002. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by all our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes.

        Covenant Compliance.     We were in compliance with all covenants in our debt agreements at December 31, 2002. Taking into account all the covenants contained in these agreements, we had approximately $115.0 million of available borrowing capacity at December 31, 2002. None of our current credit facilities includes covenant requirements or acceleration provisions based upon a change in our credit ratings. However, as proposed the new revolving loan arrangement that we expect to enter into will include a lien on our oil and gas properties that will spring into effect if the ratings on this specific loan are reduced to BB- or below by Standard & Poor's or to Ba3 or below by Moody's Investors Service.

        Redemption of Preferred Stock.     In December 2002, we redeemed all the remaining shares of our $2.28 cumulative preferred stock then outstanding, at a liquidation preference of $25.00 per share plus accrued and unpaid dividends, for a total of $14.0 million. This redemption was funded with amounts available under our Revolving Credit Facility.

Environmental

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

        Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the gathering systems acquired from EPFS, in January 2003, we identified many well sites that include underground sump tanks, pits, or tinhorns that are not properly permitted according to Wyoming Oil and Gas Conservation Commission, or WYOGCC, regulations. We have reported these violations to WYOGCC and are providing it with our remediation plan. It is our intention to remove all these underground facilities over the next several months. Based on our discussions with WYOGCC, it is our belief that it will not pursue any type of fines or penalties from us related to these assets. We believe the cost of our remediation plan will approximate $1.5 million, and EPFS has established an escrow account in that amount to reimburse us for these and other costs. In addition, at the time of the acquisition, we obtained an insurance policy that we believe will cover any additional environmental issues that may be identified over the next three years associated with these assets, up to a total exposure of $5.0 million.

        The Texas Council on Environmental Quality, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to it regarding a voluntary emissions reduction plan for the permitting of existing "grand-fathered" air emissions sources within Texas. A "grand-fathered" air emissions source is one that does not need a state-operating permit because it was constructed prior to 1971. We operate a number of these sources within Texas, including portions of our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a modernization program, which was completed in March 2002, we replaced the majority of our "grand-fathered" equipment in Texas. We believe that the potential cost of complying with these regulations for our remaining "grand-fathered" equipment will not have material adverse effect on our results of operations or financial position.

        We anticipate that the trend in environmental legislation and regulation will continue to be toward stricter standards. Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required. We are evaluating all our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements. We currently estimate our costs for compliance to be approximately $2.0 million. The new spill prevention plans must be in place for covered assets by April 2003. All modifications called for in those plans must be in place by August 2003. We are unaware of any other future environmental standards that are reasonably likely to be adopted that will have a material effect on our financial position or results of operations, but we cannot rule out that possibility.

        We are in the process of voluntarily cleaning up substances at certain facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $1.4 million for the year ended December 31, 2002, including approximately $587,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material effect on our financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

        We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counter parties and have agreements with many of these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked-to-market daily for the credit review process. Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counter parties based upon the mark-to-market value of their net exposure. We are subject to margin deposit requirements under these same agreements. In addition, we are subject to similar margin deposit requirements for our NYMEX counter parties related to our net exposures. Beginning in 2003, the prices for natural gas, crude oil and NGL products have increased significantly. For example, the NYMEX contract for March 2003 delivery of natural gas closed at $9.13 per MMbtu as compared to $2.39 per MMbtu for the March 2002 NYMEX contract. Primarily as a result of our equity hedge positions for natural gas and liquid products, we have posted margin totaling $29.8 million with various counter parties at March 3, 2003.

        We continually monitor and review the credit exposure to our marketing counter parties. As prices have increased, throughout the winter of 2002 - 2003, we have become increasingly concerned with our counter party credit exposure. As a result, we have reduced our sales of third-party natural gas volumes to reduce our credit exposure. During 2002, we incurred a total expense of $1.6 million for uncollectible accounts. This represents 0.06% of our total consolidated revenues of $2.5 billion for the year ended December 31, 2002. Additionally, beginning in 2001, we became increasingly concerned with our credit exposure to our customers, primarily a category of our customers generally known as "energy merchants." Energy merchants create liquidity in the marketplace for natural gas transactions and have historically been some of our largest suppliers and customers. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers. Although similar netting agreements have been upheld by bankruptcy courts in the past, if any of these customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

        We have identified one Master Swap Agreement containing ratings triggers. Under this agreement, either party may be required to post additional collateral in the event of a decrease in their current rating by Standard & Poor's or Moody's Investors Service. Based on our outstanding positions under this agreement and our counter party's credit rating at March 3, 2003, we were holding approximately $8.7 million of collateral.

        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 counter parties fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in these prices.

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

        Hedge Positions.     As of March 12, 2003, we have hedged approximately 53% of our projected equity natural gas volumes and approximately 78% of our estimated equity production of crude oil, condensate, and NGLs. These contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives. This ineffectiveness is primarily due to the use of crude oil swaps in hedging the variability in the sales price of butanes. During 2002, we recognized a total of $154,000 of loss from the ineffective portions of our hedges. Overall, our hedges are expected to continue to be "highly effective" under SFAS 133 in the future. In the fourth quarter of 2002, in order to properly align our hedged volumes of natural gas to our forecasted equity production for 2003, we discontinued hedge treatment on financial instruments for 6 MMcf per day. As a result, a pre-tax gain of $790,000 was reclassified into earnings in the fourth quarter of 2002 from other comprehensive income.

        To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced. To meet this requirement, we hedge both the price of the commodity and the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity. We utilize crude oil as a surrogate hedge for butanes. This typically results in an effective hedge as crude oil and butane prices historically have moved in tandem.

        Outstanding Equity Hedge Positions and the Associated Basis for 2003.     The following table details our hedge positions as of March 3, 2003. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $930,000.

Product	Quantity and NYMEX or Settlement Price	Hedge of Basis Differential
Natural gas	52,000 MMbtu per day with an average price of $3.95 per MMbtu. 20,000 MMbtu per day with a minimum price of $3.50 per MMbtu and an average maximum price of $4.43/MMbtu.	Mid-Continent—23,000 MMbtu per day with an average basis price of ($0.16) per MMbtu. Permian—5,000 MMbtu per day with an average basis price of ($0.1325) per MMbtu. Rocky Mountain—44,000 MMbtu per day with an average basis price of ($0.80) per MMbtu.
Crude Oil	55,000 Barrels of crude oil per month with an average price of $26.02 per barrel.	Not Applicable
Butanes	50,000 Barrels of crude oil per month. Floor at $24.00 per barrel. (Crude oil is used as a surrogate for butanes).	Not Applicable
Propane	100,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.50 per gallon, respectively.	Not Applicable
Ethane	125,000 Barrels per month. Average minimum and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.	Not Applicable

        Account balances related to equity and transportation hedging transactions at December 31, 2002 were $11.8 million in Current Assets from price risk management activities, $20.1 million in Current Liabilities from price risk management activities, ($3.1) million in Deferred income taxes payable, net, and a $5.4 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Shareholders' Equity. Based on the commodity prices as of December 31, 2002, the after-tax loss of $5.4 million will be re-classified from Accumulated other comprehensive income to Product Purchases during the next twelve months.

        Natural Gas Derivative Market Risk.     As of December 31, 2002, we held a notional quantity of approximately 303 Bcf of natural gas futures, swaps and options extending from January 2003 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 116 Bcf of long positions and 187 Bcf of short positions in these instruments. As of December 31, 2001, we held a notional quantity of approximately 439 Bcf of natural gas futures, swaps and options extending from January 2002 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 199 Bcf of long positions and 240 Bcf of short positions in these instruments.

        Crude Oil and NGL Derivative Market Risk.     As of December 31, 2002, we held a notional quantity of approximately 275,940 MGal of crude oil and NGL futures, swaps and options extending from January 2003 to December 2003 with a weighted average duration of approximately six months. This was comprised of approximately 138,600 MGal of long positions and 137,340 MGal of short positions in these instruments. As of December 31, 2001, we held a notional quantity of approximately 131,124 MGal of crude oil and NGL futures, swaps and options extending from January 2002 to December 2002 with a weighted average duration of approximately six months. This was comprised of approximately 61,824 MGal of long positions and 69,300 Mgal of short positions in these instruments.

        As of December 31, 2002, we did not hold any NGL futures, swaps or options for settlement beyond 2003. As of December 31, 2002, the estimated fair value of the aforementioned crude oil and NGL options and swaps held by us was approximately ($2.8) million.

        Value at Risk.     We measure market risk in our natural gas and liquid marketing portfolios using value-at-risk, 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. We began using this model for VaR in the third quarter of 2002. As of December 31, 2002, our VaR position for natural gas and liquid marketing portfolios was $412,000. This figure includes the risk related to our entire marketing portfolio of natural gas and liquid financial instruments and the related underlying physical transactions. We also measure market risk by sensitivity valuations. As of December 31, 2002, an increase in natural gas prices of $1.00 would lead to an increase in the fair value of our marketing portfolio of $1.6 million and an increase in crude oil prices of $5.00 would lead to an increase in the fair value of our marketing portfolio of $611,000. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

        Summary of Derivative Positions.     A summary of the change in our derivative position from December 31, 2001 to December 31, 2002 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2001	$	49,411
Decrease in value due to change in price		(6,800	)
Increase in value due to new contracts entered into during the period		26,052
Gains realized during the period from existing and new contracts		(68,600	)
Changes in fair value attributable to changes in valuation techniques		—
Fair value of contracts outstanding at December 31, 2002	$	63

        A summary of our outstanding derivative positions at December 31, 2002 is as follows (dollars in thousands):

	Fair Value of Contracts at December 31, 2002
Source of Fair Value	Total Fair Value			Maturing In 2003			Maturing In 2004-2005			Maturing In 2006-2007			Maturing Thereafter
Exchange published prices	$	(24,885	)	$	(25,138	)	$	253			—		—
Other actively quoted prices(1)		27,127			27,380			(196	)	$	(57	)	—
Other valuation methods(2)		(2,179	)		(2,180	)		1			—		—
Total fair value	$	63		$	62		$	58		$	(57	)	—

(1)

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

(2)

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

        Foreign Currency Derivative Market Risk.     As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 2002, the net notional value of such contracts was approximately $14.4 million in Canadian dollars, which approximates fair market value.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

        Western Gas Resources, Inc.'s Consolidated Financial Statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002:

REPORT OF MANAGEMENT

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

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

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

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

/s/  PETER A. DEA Peter A. Dea
Chief Executive Officer and President

/s/  WILLIAM J. KRYSIAK William J. Krysiak
Executive Vice President—Chief Financial Officer (Principal Financial and Accounting Officer)

REPORT OF INDEPENDENT ACCOUNTANTS

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

        In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Western Gas Resources, Inc. and its subsidiaries at December 31, 2002 and 2001, and the results of their cash flows and their operations for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As discussed in Note 4 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Denver, Colorado
February 19, 2003

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(000s, except share data)

			December 31,
			2002			2001
ASSETS
Current assets:
	Cash and cash equivalents		$	7,312		$	10,032
	Trade accounts receivable, net			253,587			220,537
	Inventory			43,482			50,773
	Assets held for sale			3,250			—
	Assets from price risk management activities			34,873			66,271
	Other			27,744			18,350
		Total current assets		370,248			365,963
Property and equipment:
	Gas gathering, processing, storage and transportation			942,147			912,003
	Oil and gas properties and equipment (successful efforts method)			252,747			193,656
	Construction in progress			104,033			106,385
				1,298,927			1,212,044
Less: Accumulated depreciation, depletion and amortization				(432,281	)		(363,737	)
Total property and equipment, net				866,646			848,307
Other assets:
	Gas purchase contracts (net of accumulated amortization of $37,232 and $35,329, respectively)			30,924			32,826
	Assets from price risk management activities			406			2,934
	Other			33,920			17,912
	Total other assets			65,250			53,672
Total assets			$	1,302,144		$	1,267,942
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	242,987		$	260,208
	Accrued expenses			51,509			23,123
	Liabilities from price risk management activities			34,811			18,075
	Dividends payable			3,464			3,767
		Total current liabilities		332,771			305,173
Long-term debt				359,933			366,667
Other long-term liabilities				1,713			2,284
Liabilities from price risk management activities				406			1,720
Deferred income taxes payable				124,253			118,746
Total liabilities				819,076			794,590
Commitments and contingent liabilities (Note 8)				—			—
Stockholders' equity:
	Preferred Stock; 10,000,000 shares authorized:
		$2.28 cumulative preferred stock, par value $.10;—and 591,136 shares issued, respectively		—			59
		$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference)		276			276
	Common stock, par value $.10; 100,000,000 shares authorized; 33,077,611 and 32,689,009 shares issued, respectively			3,329			3,293
	Treasury stock, at cost; 25,016 common shares at 12/31/02; 25,016 common shares and 44,290 $2.28 cumulative preferred shares at 12/31/01, in treasury			(788	)		(1,907	)
	Additional paid-in capital			381,066			387,505
	Retained earnings			102,292			66,128
	Accumulated other comprehensive income (loss)			(2,812	)		18,882
	Notes receivable from key employees secured by common stock			(295	)		(884	)
		Total stockholders' equity		483,068			473,352
Total liabilities and stockholders' equity			$	1,302,144		$	1,267,942

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(000s)

			Year Ended December 31,
			2002			2001			2000
Reconciliation of net income to net cash provided by operating activities:
Net income			$	50,589		$	95,637		$	56,108
Add income items that do not affect operating cash flows:
	Depreciation, depletion and amortization			77,005			64,162			57,919
	Deferred income taxes			19,614			42,815			32,712
	Distributions less than equity income, net			(2,906	)		(29	)		(1,137	)
	(Gain) loss on the sale of property and equipment			948			(10,748	)		(9,406	)
	Non-cash change in fair value of derivatives			13,788			(19,906	)		—
	Compensation expense from re-priced stock options			224			170			1,879
	Other non-cash items, net			1,809			1,405			1,804
Adjustments to working capital to arrive at net cash provided by operating activities:
	(Increase) decrease in trade accounts receivable			(35,216	)		313,215			(350,644	)
	(Increase) decrease in product inventory			7,164			(5,951	)		(9,594	)
	Decrease in parts inventory			—			440			1,612
	Decrease (increase) in other current assets			(13,329	)		(4,314	)		3,570
	Decrease (increase) in other assets and liabilities, net			348			(1,188	)		424
	Increase (decrease) in accounts payable			(16,394	)		(321,355	)		348,892
	(Decrease) increase in accrued expenses			27,492			(1,086	)		(17,877	)
		Total adjustments		(29,935	)		(20,239	)		(23,617	)
Net cash provided by operating activities				131,136			153,267			116,262
Cash flows from investing activities:
	Purchases of property and equipment, including acquisitions			(125,600	)		(163,977	)		(108,536	)
	Proceeds from the disposition of property and equipment			34,865			38,094			26,484
	Contributions to equity investees			(15,037	)		(5,774	)		—
	Distributions from equity investees			—			—			13
Net cash used in investing activities				(105,772	)		(131,657	)		(82,039	)
Cash flows from financing activities:
	Net proceeds from exercise of common stock options			6,489			5,191			2,680
	Payments for the re-purchase of preferred stock			—			(129	)		(990	)
	Payments for the redemption of preferred stock			(12,607	)		(20,591	)		—
	Payments on long-term debt			(8,333	)		(33,333	)		(27,000	)
	Borrowings under revolving credit facility			994,545			569,630			1,399,736
	Payments on revolving credit facility			(992,945	)		(528,330	)		(1,392,286	)
	Debt issue costs paid			(126	)		(97	)		(621	)
	Dividends paid			(15,107	)		(16,846	)		(16,877	)
Net cash used in financing activities				(28,084	)		(24,505	)		(35,358	)
Net decrease in cash and cash equivalents				(2,720	)		(2,895	)		(1,135	)
Cash and cash equivalents at beginning of year				10,032			12,927			14,062
Cash and cash equivalents at end of year			$	7,312		$	10,032		$	12,927

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)

			Year Ended December 31,
			2002			2001			2000
Revenues:
	Sale of gas		$	2,123,468		$	2,849,097		$	2,628,052
	Sale of natural gas liquids			309,697			424,082			590,932
	Gathering, processing and transportation revenue			65,601			55,398			53,156
	Non-cash change in fair value of derivatives			(13,788	)		19,906			—
	Other			4,720			4,679			7,951
		Total revenues		2,489,698			3,353,162			3,280,091
Costs and expenses:
	Product purchases			2,157,179			2,986,950			2,985,501
	Plant and transportation operating expense			81,530			75,533			69,892
	Oil and gas exploration and production costs			34,007			27,527			19,521
	Depreciation, depletion and amortization			77,005			64,162			57,919
	Selling and administrative expense			35,828			34,272			33,717
	(Gain) loss on sale of assets			948			(10,748	)		(9,406	)
	Earnings from equity investments			(4,453	)		(1,790	)		(1,897	)
	Interest expense			26,951			25,130			33,460
		Total costs and expenses		2,408,995			3,201,036			3,188,707
Income before income taxes				80,703			152,126			91,384
		Provision for income taxes:
	Current			10,500			13,674			850
		Deferred		19,614			42,815			32,712
		Total provision for income taxes		30,114			56,489			33,562
Income before extraordinary item				50,589			95,637			57,822
Extraordinary charge for early extinguishment of debt, net of tax benefit of $997,000				—			—			(1,714	)
Net income			$	50,589		$	95,637		$	56,108
Preferred stock requirements				(9,198	)		(11,167	)		(10,416	)
Net income attributable to common stock			$	41,391		$	84,470		$	45,692
Net income per share of common stock before extraordinary item			$	1.26		$	2.59		$	1.47
Extraordinary item per share of common stock, net of tax			$	—		$	—		$	(.05	)
Net income per share of common stock			$	1.26		$	2.59		$	1.42
Weighted average shares of common stock outstanding				32,952,543			32,579,813			32,240,755
Net income per share of common stock—assuming dilution			$	1.23		$	2.48		$	1.39
Weighted average shares of common stock outstanding—assuming dilution				33,607,560			37,022,369			32,834,641

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)

				Shares of $2.28 Cumulative Preferred Stock		$2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	Shares of $2.28 Cumulative Preferred Stock in Treasury		$2.28 Cumulative Preferred Stock			$2.625 Cumulative Convertible Preferred Stock		Common Stock		Treasury Stock			Additional Paid-In Capital			Retained (Deficit) Earnings			Accumulated Other Comprehensive Income (Loss) Net of Tax			Notes Receivable from Key Employees			Total Stockholders' Equity
Balance at December 31, 1999				1,400,000		2,760,000	32,161,731	25,016	—			140			276		3,220		(788	)		397,522			(51,064	)		1,321			(884	)		349,743
Comprehensive income:
	Net income, 2000			—		—	—	—	—			—			—		—		—			—			56,108			—			—			56,108
	Translation adjustments			—		—	—	—	—			—			—		—		—			—			—			857			—			857
Stock options exercised				—		—	199,400	—	—			—			—		45		—			2,635			—			—			—			2,680
Tax benefit related to stock options				—		—	—	—	—			—			—		—		—			—			—			—			—			—
Loans forgiven				—		—	—	—	—			—			—		—		—			—			—			—			—			—
Dividends declared on common stock				—		—	—	—	—			—			—		—		—			—			(6,448	)		—			—			(6,448	)
Dividends declared on $2.28 cumulative preferred stock				—		—	—	—	—			—			—		—		—			—			(3,171	)		—			—			(3,171	)
Dividends declared on $2.625 cumulative convertible preferred stock				—		—	—	—	—			—			—		—		—			—			(7,245	)		—			—			(7,245	)
Repurchase of $2.28 cumulative preferred stock				—		—	—	—	39,190			—			—		—		(990	)		—			—			—			—			(990	)
Balance at December 31, 2000				1,400,000		2,760,000	32,361,131	25,016	39,190		$	140		$	276	$	3,265	$	(1,778	)	$	400,157		$	(11,820	)	$	2,178		$	(884	)	$	391,534
Comprehensive income:
	Net income, 2001			—		—	—	—	—			—			—		—		—			—			95,637			—			—			95,637
	Translation adjustments			—		—	—	—	—			—			—		—		—			—			—			(440	)		—			(440	)
		Cumulative effect of change in accounting principal		—		—	—	—	—			—			—		—		—			—			—			(22,527	)		—			(22,527	)
		Reclassification adjustment for settled contracts		—		—	—	—	—			—			—		—		—			—			—			21,988			—			21,988
		Changes in fair value of outstanding hedge positions		—		—	—	—	—			—			—		—		—			—			—			5,772			—			5,772
		Fair value of new hedge positions		—		—	—	—	—			—			—		—		—			—			—			11,911			—			11,911
		Ending accumulated derivative gain		—		—	—	—	—			—			—		—		—			—			—			17,144			—			17,144
			Total comprehensive income, net of tax																															112,341
Stock options exercised				—		—	327,878	—	—			—			—		28		—			5,163			—			—			—			5,191
Effect of re-priced options				—		—	—	—	—			—			—		—		—			(170	)		—			—			—			(170	)
Tax benefit related to stock options				—		—	—	—	—			—			—		—		—			1,584			—			—			—			1,584
Dividends declared on common stock				—		—	—	—	—			—			—		—		—			—			(6,524	)		—			—			(6,524	)
Dividends declared on $2.28 cumulative preferred stock				—		—	—	—	—			—			—		—		—			—			(2,640	)		—			—			(2,640	)
Dividends declared on $2.625 cumulative convertible preferred stock				—		—	—	—	—			—			—		—		—			—			(7,244	)		—			—			(7,244	)
Redemption of $2.28 cumulative preferred stock				(808,864	)	—	—	—	—			(81	)		—		—		—			(19,229	)		(1,281	)		—			—			(20,591	)
Repurchase of $2.28 cumulative preferred stock				—		—	—	—	5,100			—			—		—		(129	)		—			—			—			—			(129	)
Balance at December 31, 2001				591,136		2,760,000	32,689,009	25,016	44,290		$	59		$	276	$	3,293	$	(1,907	)	$	387,505		$	66,128		$	18,882		$	(884	)	$	473,352
Comprehensive income:
	Net income, 2002			—		—	—	—	—			—			—		—		—			—			50,589			—			—			50,589
	Other comprehensive income from equity investees			—		—	—	—	—			—			—		—		—			—			—			556			—			557
	Translation adjustments			—		—	—	—	—			—			—		—		—			—			—			283			—			283
		Reclassification adjustment for settled contracts		—		—	—	—	—			—			—		—		—			—			—			(17,142	)		—			(17,142	)
		Changes in fair value of outstanding hedge positions		—		—	—	—	—			—			—		—		—			—			—			(119	)		—			(119	)
		Fair value of new hedge positions		—		—	—	—	—			—			—		—		—			—			—			(5,272	)		—			(5,272	)
		Change in accumulated derivative comprehensive income		—		—	—	—	—			—			—		—		—			—			—			(22,533	)		—			(22,533	)
			Total comprehensive income, net of tax	—		—	—	—	—			—			—		—		—			—			—			—			—			28,895
Stock options exercised				—		—	388,602	—	—			—			—		36		—			5,975			—			—			—			6,011
Effect of re-priced options				—		—	—	—	—			—			—		—		—			478			—			—			—			478
Officer loans forgiven				—		—	—	—	—			—			—		—		—			—			—			—			589			589
Tax benefit related to stock options				—		—	—	—	—			—			—		—		—			1,154			—			—			—			1,154
Dividends declared on common stock				—		—	—	—	—			—			—		—		—			—			(6,603	)		—			—			(6,603	)
Dividends declared on $2.28 cumulative preferred stock				—		—	—	—	—			—			—		—		—			—			(957	)		—			—			(957	)
Dividends declared on $2.625 cumulative convertible preferred stock				—		—	—	—	—			—			—		—		—			—			(7,244	)		—			—			(7,244	)
Redemption of $2.28 cumulative preferred stock				(591,136	)	—	—	—	(44,290	)		(59	)		—		—		1,119			(14,046	)		379			—			—			(12,607	)
Balance at December 31, 2002				—		2,760,000	33,077,611	25,016	—		$	—		$	276	$	3,329	$	(788	)	$	381,066		$	102,292		$	(2,812	)	$	(295	)	$	483,068

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

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—NATURE OF ORGANIZATION

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

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

        The Company has also completed two public offerings of preferred stock. In November 1992, the Company issued 1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation preference of $25 per share, at a public offering price of $25 per share, redeemable at the Company's option on or after November 15, 1997. In 2000, the Company re-purchased 39,190 of the $2.28 Cumulative Preferred Stock for a total consideration of approximately $1.0 million. In 2001, the Company purchased in open market transactions an additional 5,100 shares of this preferred stock for a total cost, including broker commissions, of approximately $129,000, or an average of $25.29 per share of preferred stock. In December 2001, the Company redeemed 808,864 shares of this preferred stock at the liquidation preference for total proceeds of $20.6 million including accrued and unpaid dividends. In December 2002, the Company redeemed the remaining 546,846 shares of this preferred stock at the liquidation preference for total proceeds of $14.0 million including accrued and unpaid dividends. This redemption was funded with amounts available under the Revolving Credit Facility.

        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 $39.75.

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

Significant Projects and Asset Divestitures

        Toca Processing Facility.     June 2002, the Company entered into an agreement for the sale of its Toca processing facility in Louisiana. This sale closed in September 2002. The sale price was $32.2 million, subject to accounting adjustments, and resulted in a pre-tax loss of approximately $448,000. During the year ended December 31, 2002, this facility generated net after-tax earnings of approximately $683,000, or $.02 per share of common stock, respectively. The Company believes the results from this facility are immaterial for separate presentation as a discontinued operation. Approximately $15.0 million of the proceeds received from this asset sale were initially used to reduce amounts outstanding on the Company's Revolving Credit Facility. At December 31, 2002, the remaining amount of $17.2 million was on deposit with a trustee in anticipation of the completion of a like-kind exchange transaction and was reflected on the Consolidated Balance Sheet under the caption Other current assets. These funds, along with additional amounts drawn on our Revolving Credit Facility, were used in a January 2003 acquisition of several gathering systems.

        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 in northeast Wyoming. During the years ended December 31, 2002, 2001 and 2000, the Company expended approximately $71.0 million, $82.1 million and $59.1 million, respectively, on this project.

        In December 1998, the Company joined with other industry participants to form the Fort Union Gas Gathering, L.L.C. ("Fort Union"), to construct a gathering pipeline and treater in the Powder River Basin in northeast Wyoming. The Company owns an approximate 13% interest in Fort Union and is the construction manager and field operator.

        Green River Basin.     The Company's assets in southwest Wyoming are comprised of the Granger and Lincoln Road facilities (collectively the "Granger Complex"), its 50% equity interest in Rendezvous Gas Services, L.L.C. ("Rendezvous"), the Red Desert facility and production from the Jonah Field and Pinedale Anticline areas. During the years ended December 31, 2002, 2001 and 2000, the Company expended approximately $36.2 million, $27.2 million and $8.0 million, respectively, in this area.

        In 2001, the Company sold a 50% interest in a segment of the gathering system behind its Granger facility, along with associated field compression to an unrelated third party for $5.2 million. Together, the Company and the third party contributed their respective interests in this system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to a newly formed limited liability corporation named Rendezvous Gas Services, L.L.C. Each company owns a 50% interest in Rendezvous, and the Company serves as field operator of its systems. Rendezvous was formed to gather gas along the Pinedale Anticline for blending or processing at either the Company's Granger Complex or at Questar's Blacks Fork processing facility.

        Pinnacle Gas Treating, Inc.     In December 2000, the Company signed an agreement with Anadarko Petroleum Corporation for the sale of the stock of the Company's wholly owned subsidiary Pinnacle Gas Treating, Inc. for approximately $38.0 million. The sale closed in January 2001 and resulted in an approximate pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.

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

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

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        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.

        Inventories.     The cost of gas and NGL inventories are determined by the weighted average cost method on a location-by-location basis. Residue and NGL inventory covered by derivative contracts is accounted for on a specific identification basis. Product inventory includes $42.1 million and $48.3 million of gas and $1.4 million and $2.5 million of NGLs at December 31, 2002 and 2001, respectively.

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

        Depreciation is provided using the straight-line method based on the estimated useful life of each facility, which ranges from three to 35 years. Useful lives are determined based on the shorter of the life of the equipment or the reserves serviced by the equipment. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production.

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

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

        Foreign Currency Adjustments.     The Company has a subsidiary in Canada. The assets and liabilities associated with this subsidiary are translated into U.S. dollars at the exchange rate as of the balance sheet date and revenues and expenses at the weighted-average of exchange rates in effect during each reporting period. The translation gains (losses) for the years ended December 31, 2002, 2001 and 2000 were $283,000, $(440,000) and $857,000, respectively, net of tax.

        Revenue Recognition.     In the 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 to the product. These revenues are recorded on a gross sales versus sales net of purchases basis as the Company obtains title to all the gas and NGLs that it buys including third-party purchases, and bears the risk of loss and credit exposure on these transactions. For its marketing activities the Company utilizes mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods. 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.

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

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

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

        Comprehensive Income.     Accumulated other comprehensive income (loss) is reported as a separate component of stockholders' equity. Accumulated other comprehensive income (loss) includes cumulative translation adjustments for foreign currency transactions and the change in fair market value of cash flow hedges. The Company's accumulated derivative losses at December 31, 2002 total $5.4 million and will be reclassified into earnings during 2003. These items are separately reported on the Consolidated Statement of Changes in Stockholders' Equity.

        Impairment of Long-Lived Assets.     SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121") required that long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Effective for the Company's year ended December 31, 2002, SFAS No. 121 was superseded by SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144 also requires that long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company reviews its assets at the plant facility, related group of plant facilities or the oil and gas producing property levels. In order to determine whether an impairment exists, the Company compares its net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. There were no write-downs in 2002, 2001or 2000.

        Earnings Per Share of Common Stock.     The Company follows SFAS No. 128, "Earnings per Share" ("SFAS No. 128"), which requires that earnings per share and earnings per share—assuming dilution be calculated and presented on the Consolidated Statement of Operations. In accordance with SFAS No. 128, earnings 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 income less preferred stock dividends. The Company declared preferred stock dividends of $8.2 million, $11.2 million and $10.4 million for each of the years ended December 31, 2002, 2001 and 2000, respectively. SFAS No. 128 dictates that the computation of earnings per share shall not assume conversion, exercise or contingent issuance of securities that would have an anti-dilutive effect on earnings per share. Common stock options, which are potential common shares, increased the number of common shares used in the computation by 655,017 and 593,886 in 2002 and 2000, respectively. The computations for the years ended December 31, 2002 and 2000 were not adjusted to reflect the conversion of the Company's $2.625 Cumulative Convertible Preferred Stock outstanding. In those years, the shares are antidilutive as the incremental shares result in an increase in earnings per share after giving effect to the preferred dividend requirements. The computation for the year ended December 31, 2001 reflects the conversion of the Company's $2.625 Cumulative Convertible Preferred Stock and dilutive stock options totaling 4,442,556.

        Concentration of Credit Risk.     Financial instruments 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 is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations.

        The Company continually monitors and reviews the credit exposure to its marketing counter parties. This review has resulted in a reduction in sales volumes with various counter parties in order to maintain acceptable credit exposures. During 2002, 2001 and 2000, the Company reserved approximately $1.6 million, $2.7 million and $1.6 million for doubtful accounts through a charge to Selling and administrative expense. The Company records a reserve for doubtful accounts on a specific identification basis and the balance in the reserve for doubtful accounts was $3.9 million and $2.3 million, respectively at December 31, 2002 and 2001. During the years ended December 31, 2002, 2001 and 2000, the Company sold gas to a variety of customers including end-users, pipelines, energy merchants, LDCs and others. Two customers accounted for approximately 10% of the Company's consolidated revenues from the sale of gas, or 9% of total consolidated revenue, for the year ended December 31, 2002. One of these customers is an energy merchant and the other customer is an electric utility. One customer accounted for approximately 5% of the Company's consolidated revenues from the sale of gas, or 4% of total consolidated revenue, for the year ended December 31, 2001. This customer is a wholly owned subsidiary of a major integrated oil company.

        During the years ended December 31, 2002, 2001 and 2000, the Company sold NGLs to a variety of customers including end-users, fractionators, chemical companies, energy merchants and other customers. In 2002, three customers accounted for approximately 38% of the Company's consolidated revenues from the sale of NGLs, or 5% of total consolidated revenue. One of these customers is a large integrated energy company, another is a large petrochemical company and the third is an energy merchant. In 2001, three customers accounted for approximately 37% of the Company's consolidated revenues from the sale of NGLs, or 5% of total consolidated revenue. These customers were all large integrated energy companies.

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

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

        Supplementary Cash Flow Information.     Interest paid was $28.1 million, $30.2 million and $36.5 million, respectively, for the years ended December 31, 2002, 2001 and 2000. Capitalized interest associated with construction of new projects was $1.7 million, $4.7 million and $3.4 million, respectively, for the years ended December 31, 2002, 2001 and 2000. Income taxes paid were $1.5 million, $18.7 million and $400,000, respectively, for the years ended December 31, 2002, 2001 and 2000.

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

        In March 2000, the FASB issued Interpretation No. 44, an interpretation of APB Opinion No. 25, "Accounting for Certain Transactions Involving Stock Compensation," regarding the accounting treatment of re-priced stock options. This interpretation became effective July 1, 2000. Under this interpretation, the Company is required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which its stock price at the end of any quarter exceeds $21 per share. The Company had options covering 69,500, 118,028 and 148,133 common shares outstanding at December 31, 2002, 2001 and 2000, respectively, which were treated as re-priced options. Based on the Company's stock price at December 31, 2002, 2001and 2000 of $36.85, $32.32 and $33.69 per share, respectively, additional income of $224,000, income of $170,000, and expense of $1.9 million was recorded in the years ended December 31, 2002, 2001, and 2000.

        SFAS No. 123 encourages companies to record compensation expense for stock-based compensation plans at fair value. As permitted under SFAS No. 123, the Company has elected to continue to measure compensation costs for such plans as prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures for each year that a statement of operations is presented. Such information was only calculated for the options granted under the 1993, 1997 and 1999 Stock Option Plans, the 1999 Non-Employee Directors Stock Option Plan and the 2002 Stock Option Plan and the 2002 Non-employee Directors Stock Option Plan, as there were no grants under any other plans. There were no grants under the 1997 Plan during the years ended December 31, 2002 and 2001. The weighted average fair value of options granted under the 1999 Plan was $17.36, $19.26 and $21.20 for the years ended December 31, 2002, 2001 and 2000, respectively. The weighted average fair value of options granted under the Chief Executive Officer's Plan was $21.13 for the year ended December 31, 2001. The weighted average fair value of options granted under the 2002 Directors' Plan and the 2002 Plan were $22.50 and $17.44, respectively, for the year ended December 31, 2002. The weighted average fair value of options granted was estimated using the Black-Scholes option-pricing model with the following assumptions:

	1999 Plan									2002 Plan			2002 Directors' Plan			Chief Executive Officer's Plan
	2002			2001			2000			2002			2002			2001
Risk-free interest rate		3.40	%		5.16	%		5.95	%		3.41	%		4.93	%		5.16	%
Expected life (in years)		5			5			5			5			5			5
Expected volatility		55	%		56	%		54	%		55	%		56	%		56	%
Expected dividends (quarterly)	$	0.05		$	0.05		$	0.05		$	0.05		$	0.05		$	0.05

        Had compensation expense for the Company's 2002, 2001 and 2000 grants for stock-based compensation plans been determined consistent with the fair value method under SFAS No. 123, 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):

	2002				2001					2000
	As Reported		Pro forma		As Reported			Pro forma		As Reported		Pro forma
Net income	$	50,589	$	47,978	$	95,637		$	93,120	$	56,108	$	54,374
Net income attributable to common stock		41,391		39,780		84,470			81,954		45,692		43,958
Earnings per share of common stock		1.26		1.18		2.59			2.52		1.42		1.36
Earnings per share of common stock—assuming dilution		1.23		1.15		2.48			2.41		1.39		1.34
Stock-based employee compensation cost, net of related tax effects, included in net income		375		—		(68	)		—		1,228		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	2,987	$	—		$	2,448	$	—	$	3,016

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

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

        Recently Issued Accounting Pronouncements.     In June 2001, the Financial Accounting Standards Board, (the "FASB"), issued SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. SFAS No. 142 changes the method in which goodwill and other intangible assets are recorded and amortized. SFAS No. 142 did not have an immediate impact on the Company as it does not have any goodwill recorded in its financial statements.

        In June 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. The Company is in the process of determining its asset retirement costs in accordance with SFAS No. 143 and will adopt it on January 1, 2003. The Company expects to record a $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 $10.7 million pre-tax loss from the Cumulative effect of a change in accounting principle in the first quarter of 2003.

        In April 2002, the FASB issued SFAS No. 145, "Rescission of FAS Statements No. 4, 44 and 64, Amendment of FAS Statement No. 13, and Technical Corrections," which is generally effective for fiscal years beginning after May 15, 2002. Through the rescission of SFAS Statements 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishment of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. The Company has adopted SFAS No. 145 for its fiscal year beginning January 1, 2003.

        In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force, or EITF, Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." The Company does not believe that SFAS No. 146 will have a material impact on its earnings or financial position.

        In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure, an amendment of SFAS No. 123." SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for fiscal years ending after December 31, 2002 and for interim periods beginning after December 15, 2002. The Company does not believe that SFAS No. 148 will have a material impact on its earnings or financial position as the Company continues 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 will comply with requirements of SFAS No. 148 for interim periods beginning with the first quarter of 2003.

        At an October 25, 2002 special meeting of the EITF, a consensus was reached to rescind EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." This impact of this decision is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The EITF also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. Energy trading contracts not within the scope of SFAS No. 133 purchased after October 25, 2002, but prior to the implementation of the consensus are not permitted to apply mark-to-market accounting. EITF 02-03 was subsequently amended in January 2003 to further define energy trading contracts. Upon entering into a physical or derivative transaction, the Company is now required to designate its intention to either hold the contract to maturity or trade the contract prior to its maturity. The rescission of EITF 98-10 and the issuance of EITF 02-03 will not require any change to the Company's current accounting treatment for revenues or gains or losses from derivative activities.

        In November 2002, the FASB issued Interpretation No. 45, ("FIN 45"), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of a guarantee. FIN 45 also requires additional disclosures about the guarantees an entity has issued. The Company will apply the recognition provisions of FIN 45 prospectively to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for the Company's financial statements for the year ending December 31, 2002. The Company is currently evaluating the potential impact that the recognition provisions of FIN 45 will have on its consolidated financial condition and results of operations.

        In January 2003, the FASB issued Interpretation No. 46, ("FIN 46"), "Consolidation of Variable Interest Entities." FIN 46 provides guidance on how to identify a variable interest entity ("VIE") and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company's consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46 must be adopted at the beginning of the first interim or annual reporting period beginning after June 15, 2003. While the Company is currently evaluating the potential impact of the adoption of FIN 46, the Company believes that it will not be subject to the consolidation or disclosure requirements of FIN 46.

        Reclassifications.     Certain prior years' amounts in the consolidated financial statements and related notes have been reclassified to conform to the presentation used in 2002.

NOTE 3—RELATED PARTIES

        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. All transactions entered into by the Company with its related parties were consummated in the ordinary course of business and on terms that would be comparable to those obtained from third parties.

        Fort Union.     In December 1998, the Company joined with other industry participants to form the Fort Union Gas Gathering, L.L.C. ("Fort Union"), to construct a gathering pipeline and treater in the Powder River Basin in northeast Wyoming. At December 31, 2002 and 2001, the Company owned an approximate 13% interest in Fort Union and is the construction manager and field operator. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by the Company of approximately $900,000. In 1999, the Company entered into a ten-year agreement for firm gathering services on 60 MMcf per day of capacity for $0.14 per Mcf on Fort Union. In 2001, Fort Union was expanded. The expansion costs totaled approximately $22.0 million and were again project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. In the fourth quarter of 2001, the Company made an additional equity contribution to Fort Union of approximately $500,000. Also in connection with the expansion, the Company increased its commitment for firm gathering services to a total of 83 MMcf per day of capacity at $0.14 per Mcf. All participants in Fort Union have guaranteed Fort Union's payment of the project financing on a proportional basis resulting in the Company's guarantee of $6.3 million of the debt of Fort Union. This guarantee is not reflected on the Consolidated Balance Sheet. The Company acts as field operator of Fort Union and charges a monthly overhead fee to cover such services. In 2002, 2001 and 2000, the Company received overhead fees from Fort Union totaling $507,000, $483,000 and $72,000, respectively, and the Company paid to Fort Union a total of $5.3 million, $3.3 million and $3.1 million for gathering services, respectively. At December 31, 2002 and 2001, the Company had a net amount due to Fort Union of $258,000 and $76,000, respectively.

        Rendezvous.     At December 31, 2002 and 2001, the Company owned a 50% interest in Rendezvous Gas Services, L.L.C 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. Rendezvous was expanded during 2002 and 2001, and at December 31, 2002, the Company had a total of $22.8 million invested in this venture. The Company charges a monthly overhead fee to act as field operator of Rendezvous. In 2002 and 2001, the Company received overhead fees from Rendezvous totaling $100,000 and $25,000, respectively, and the Company paid to Rendezvous a total of $2.2 million in 2002 for gathering services. The Company paid no fees for gathering in 2001. At December 31, 2002 and 2001, the Company had a net amount due to Rendezvous of $3.6 million and $126,000, respectively.

        Westana.     In prior years, the Company had a 50% ownership interest in Westana Gathering Company ("Westana"). This joint venture gathered natural gas for third parties in Oklahoma. In February 2000, the Company acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million and Westana was dissolved. The Company acted as operator of Westana and charged a monthly overhead fee to cover such services. In 2000, the Company received overhead fees from Westana totaling $62,000.

        Officer Transactions.     The Company has entered into agreements committing the Company to loan to certain key employees an amount sufficient to exercise their options as each portion of their options vests under the Key Employees' Incentive Stock Option Plan. The loan and accrued interest will be forgiven if the employee is continually employed by the Company and upon a resolution of the board of directors. In May, July and December 2002, the Company forgave loans related to 62,500 shares of Common Stock totaling $703,000. Pursuant to the terms of an agreement entered into in 2001, the remaining loan will be forgiven in May 2003. There were no loans forgiven in 2001 or 2000. As of December 31, 2002 and 2001, loans related to 27,500 and 75,000 shares of Common Stock totaling $295,000 and $803,000, respectively, were outstanding under these programs. The remaining loan is secured by a portion of the Common Stock issued upon exercise of the options and are accounted for as a reduction of stockholders' equity. In prior years, the Company has reserved for the forgiveness of these loans.

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

NOTE 4—COMMODITY RISK MANAGEMENT

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

        The Company utilizes a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter market ("OTC") to accomplish these objectives. 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 uses futures, swaps and options to reduce price risk and basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

        The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX") and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. The Company conducts its standard credit review of OTC counter parties 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 exposures. OTC exposure is marked-to-market daily for the credit review process. The Company's OTC credit risk exposure is partially limited by its ability to require a margin deposit from its major counter parties based upon the mark-to-market value of their net exposure. The Company is subject to margin deposit requirements under these same agreements. In addition, the Company is subject to similar margin deposit requirements for its NYMEX counter parties related to its net exposures. At December 31, 2002, the Company had posted margin totaling $19.6 million with various counter parties.

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

        For 2003, the Company has hedged approximately 53% of its projected equity natural gas volumes and approximately 78% of its estimated equity production of crude oil, condensate, and NGLs. These contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives. This ineffectiveness is primarily due to the use of crude oil swaps in hedging the variability in the sales price of butanes. During 2002 the Company recognized a total of $154,000 of losses from the ineffective portions of its hedges. There were no ineffective portions of its hedges recognized in 2001. Overall, the Company's hedges are expected to continue to be "highly effective" under SFAS 133 in the future. In the fourth quarter of 2002, in order to properly align the Company's hedged volumes of natural gas to its forecasted equity production for 2003, the Company discontinued hedge treatment on financial instruments for 6 MMcf per day. As a result, a pre-tax gain of $790,000 was reclassified into earnings in the fourth quarter of 2002 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 either 2001 or 2000.

        To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of the forecasted transaction being hedged so that the Company's exposure to the risk of commodity price changes is reduced. To meet this requirement, the Company hedges both the price of the commodity and the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity. The Company utilizes crude oil as a surrogate hedge for butanes. This typically results in an effective hedge as crude oil and butane prices historically have moved in tandem.

        Account balances related to equity hedging transactions at December 31, 2002 were $11.8 million in Current Assets from price risk management activities, $20.1 million in Current Liabilities from price risk management activities, ($3.1) million in Deferred income taxes payable, net, and a $5.4 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Shareholders' Equity. Based on the commodity prices as of December 31, 2002, the after-tax loss of $5.4 million will be re-classified from Accumulated other comprehensive income to Product Purchases during the next twelve months.

        Natural Gas Derivative Market Risk.     As of December 31, 2002, the Company held a notional quantity of approximately 303 Bcf of natural gas futures, swaps and options extending from January 2003 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 116 Bcf of long positions and 187 Bcf of short positions in these instruments. As of December 31, 2001, the Company held a notional quantity of approximately 439 Bcf of natural gas futures, swaps and options extending from January 2002 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 199 Bcf of long positions and 240 Bcf of short positions in these instruments.

        Crude Oil and NGL Derivative Market Risk.     As of December 31, 2002, the Company held a notional quantity of approximately 275,940 MGal of NGL futures, swaps and options extending from January 2003 to December 2003 with a weighted average duration of approximately six months. This was comprised of approximately 138,600 MGal of long positions and 137,340 MGal of short positions in these instruments. As of December 31, 2001, the Company held a notional quantity of approximately 131,124 MGal of NGL futures, swaps and options extending from January 2002 to December 2002 with a weighted average duration of approximately six months. This was comprised of approximately 61,824 MGal of long positions and 69,300 MGal of short positions in these instruments.

        As of December 31, 2002, the Company did not hold any NGL futures, swaps or options for settlement beyond 2003. As of December 31, 2002, the estimated fair value of the aforementioned crude oil and NGL options held by the Company was approximately $(2.8) million.

        Foreign Currency Derivative Market Risk.     As a normal part of our business, the Company enters into physical gas transactions which are payable in Canadian dollars. The Company enters into forward purchases and sales of Canadian dollars from time to time to fix the cost of its future Canadian dollar denominated natural gas purchase, sale, storage and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 2002, the net notional value of such contracts was approximately $14.4 million in Canadian dollars, which approximated fair market value. As of December 31, 2001, the net notional value of such contracts was approximately $12.7 million in Canadian dollars, which again approximated its fair market value.

NOTE 5—DEBT

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

		December 31,
		2002		2001
Master Shelf and Subordinated Notes		$	263,333	$	271,666
Variable Rate Revolving Credit Facility			96,600		95,001
	Total long-term debt	$	359,933	$	366,667

        Revolving Credit Facility.     The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a $167 million Revolving Credit Facility, or Tranche B, which matures on March 31, 2004. At December 31, 2002, $96.6 million was outstanding under this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. The Company has the option to determine which rate will be used. The Company also pays a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on its debt to capitalization ratio and range from .75% to 2.00%. At December 31, 2002, the interest rate payable on borrowings under this facility was 2.6%. The Company is required to maintain a total debt to capitalization ratio of not more than 55%, and a senior debt to capitalization ratio of not more than 35%. The agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest and dividends on preferred stock for the same period. The ratio must exceed 3.25 to 1.0. This facility also limits the Company's ability to enter into operating and sale-leaseback transactions. This facility is guaranteed and secured via a pledge of the stock of all of its material subsidiaries.

        Master Shelf Agreement.     In December 1991, the Company entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31, 2002 are as indicated in the following table (000s):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	8,333	7.99	%	October 27, 2003	single payment at maturity
December 27, 1993		25,000	7.23	%	December 27, 2003	single payment at maturity
October 27, 1994		25,000	9.24	%	October 27, 2004	single payment at maturity
July 28, 1995		50,000	7.61	%	July 28, 2007	$10,000 on each of July 28, 2003 through 2007
	$	108,333

        Under the Company's agreement with Prudential, it is required to maintain a current ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 35%. This agreement also requires an EBITDA to interest ratio of not less than 3.75 to 1.0 and an EBITDA to interest on senior debt ratio of not less than 5.50 to 1.0. EBITDA in these calculations excludes certain non-recurring items. In addition, this agreement contains a calculation limiting dividends and other restricted payments including preferred stock redemptions. Under this limitation, approximately $78.3 million was available for restricted payments at December 31, 2002. This facility also limits the Company's ability to enter into operating and sale-leaseback transactions. The Company is currently paying an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee will continue until it receives an implied investment grade rating on its senior secured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed by, and secured via, a pledge of the stock of all of its material subsidiaries.

        In October 2002, the Company funded a required principal repayment under the Master Shelf Agreement of $8.3 million with funds available under the Revolving Credit Facility. During 2003, the Company is required to make principal payments totaling $43.3 million and intends to fund these with amounts 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 tradeable notes under the same terms and conditions. The Senior Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants that include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends, approximately $42.8 million was available at December 31, 2002. The Senior Subordinated Notes are unsecured and are guaranteed on a subordinated basis by all the Company's material subsidiaries. The Company incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes.

        Covenant Compliance.     The Company was in compliance with all covenants in its debt agreements at December 31, 2002. Taking into account all the covenants contained in these agreements, the Company had approximately $115.0 million of available borrowing capacity at December 31, 2002. None of our credit facilities include covenant requirements or acceleration provisions based upon a change in our credit ratings.

        Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2002 (000s):

2003		$	43,333
2004			131,600
2005			10,000
2006			10,000
2007			10,000
Thereafter			155,000
	Total	$	359,933

NOTE 6—FINANCIAL INSTRUMENTS

        The Company using available market information and valuation methodologies has determined the estimated fair values of the Company's financial instruments. 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.

	December 31, 2002				December 31, 2001
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(000s)				(000s)
Cash and cash equivalents	$	7,312	$	7,312	$	10,032	$	10,032
Trade accounts receivable		253,587		253,587		220,537		220,537
Accounts payable		242,987		242,987		260,208		260,208
Long-term debt		359,933		365,190		366,667		370,329
Derivative contracts	$	63	$	63	$	49,411	$	49,411

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

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

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

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

NOTE 7—INCOME TAXES

        The provision (benefit) for income taxes for the years ended December 31, 2002, 2001 and 2000, excluding the tax effect of the extraordinary items, is comprised of (000s):

			2002		2001			2000
Current:
	Federal		$	9,404	$	14,074		$	250
	State			1,096		(400	)		600
	Total Current			10,500		13,674			850
Deferred:
	Federal			18,967		41,225			31,497
	State			647		1,590			1,215
	Total Deferred			19,614		42,815			32,712
		Total tax provision (benefit)	$	30,114	$	56,489		$	33,562

        The tax benefit allocated to the extraordinary charges was $997,000 for the year ended December 31, 2000. There were no extraordinary charges in 2002 or 2001.

        Temporary differences and carry-forwards which give rise to the deferred tax liabilities (assets) at December 31, 2002 and 2001, net of the tax effect of the extraordinary items, are as follows (000s):

		2002			2001
Property and equipment		$	175,164		$	167,663
Differences between the book and tax basis of acquired assets			12,101			11,560
Hedging derivatives			(3,118	)		9,835
	Total deferred income tax liabilities		184,147			189,058
Alternative Minimum Tax ("AMT") credit carry-forwards			(46,076	)		(36,672	)
Net Operating Loss ("NOL") carry-forwards			(13,818	)		(33,640	)
	Total deferred income tax assets		(59,894	)		(70,312	)
	Net deferred income taxes payable	$	124,253		$	118,746

        The change in the net deferred income taxes in 2002 and 2001 includes a $1.2 million and $1.6 million tax benefit, respectively, associated with the exercise of incentive stock options. The Company expects to realize such tax benefit.

        The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes, before the tax effect of extraordinary items, for the years ended December 31, 2002, 2001 and 2000 are summarized as follows (000s):

		2002		%	2001		%	2000		%
Income tax before effect of extraordinary item at statutory rate		$	28,246	35.0	$	53,245	35.0	$	31,984	35.0
State income taxes, net of federal benefit			968	1.2		2,130	1.4		1,280	1.4
Canada income taxes, effect of disallowed loss on sale of stock and other miscellaneous items			900	1.1		1,114	.7		298	.3
	Total	$	30,114	37.3	$	56,489	37.1	$	33,562	36.7

        At December 31, 2002, the Company had NOL carry-forwards for federal and state income tax purposes and AMT credit carry-forwards for federal income tax purposes of approximately $38.2 million and $46.1 million, respectively. These carry-forwards expire as follows (000s):

Expiration Dates		NOL		AMT
2018		$	38,175	$	—
No expiration			—		46,076
	Total	$	38,175	$	46,076

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

NOTE 8—COMMITMENTS AND CONTINGENT LIABILITIES

Litigation.

Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. (together the Plaintiffs) v. Williams Production RMT Company., (Defendant), Civil Action No. CO2-10-394, District Court, County of Sheridan, Wyoming. On October 23, 2002, Plaintiffs filed a complaint for declaratory relief and damages related to a dispute arising under a Development Agreement, a Purchase and Sale Agreement, and an Operating Agreement, (collectively, the "Agreements") between the Plaintiffs and Barrett Resources Corporation, or Barrett, dated on or about October 30, 1997, as each may have been amended. The dispute centers on Defendant's acquisition of Barrett by merger consummated on August 2, 2001. Plaintiffs allege that they were entitled to a preferential right to purchase certain properties of Barrett located in the Powder River Basin of Wyoming under the Agreements and that Plaintiffs' consent was required prior to Barrett's assignment of its interests in the Agreements to the Defendant. Plaintiffs also allege that Barrett (now Defendant) should no longer be the operator of these properties as a consequence of the merger transaction.

        In the fourth quarter of 2002, the Defendant asserted breach of contract claims against the Company. The Defendant also claimed damages under its gathering agreement with the Company. The Company believes that the Defendant's assertions have no merit. The Company has also asserted breach of contract claims against the Defendant for its operating practices. The parties have agreed to begin mediation of these issues in the first quarter of 2003. At this time, the Company is unable to predict the outcome of this litigation or the claims scheduled for mediation.

Western Gas Resources, Inc. v. Amerada Hess Corporation, District Court, Denver County, Colorado, Civil Action No. 00-CV-1433. The Company was a defendant in prior litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources, Inc., United States District Court, District of Colorado, Civil Action No. 97-WM-1332, which was settled in 2000 for an amount which did not have a material impact on the Company's results of operations or financial position. The Company is seeking reimbursement from Amerada Hess under a contractual indemnity. The Company has amended its original complaint and requested a jury trial in this case. Both parties filed cross motions for summary judgment. On April 19, 2002, the trial court ruled on the parties' cross motions for summary judgment in favor of Amerada Hess, indicating that Amerada Hess has no obligation to indemnify the Company in this matter. On May 31, 2002, the Company appealed the trial court decision to the Colorado Court of Appeals. Amerada Hess filed a motion to dismiss the appeal, which was denied by the Colorado Court of Appeals on July 29, 2002. All briefs by the parties have been filed and the parties are awaiting a decision. At this time, the Company is unable to predict the outcome of this appeal.

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 is a defendant in litigation, along with 300 natural gas companies in 74 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 31 U. 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 is in the initial stages to determine if this matter qualifies as a qui tam (or class) action. On October 9, 2002, the court dismissed Mr. Grynberg's valuation claims, and he has appealed this decision. The Company believes that Mr. Grynberg's claims are baseless and without merit and intends to vigorously contest the allegations in this case. At this time, the Company is unable to predict the outcome of this matter.

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30. The Company is a defendant in litigation, 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. On January 13, 2003, a hearing was held to determine whether this matter could be certified as a class action. The Company is awaiting the court's decision on the class certification. The Company believes that Mr. Price's claims are baseless and without merit and intends to vigorously contest the allegations in this case. At this time, the Company is unable to predict the outcome of this matter.

Texas Natural Resource Conservation Commission (TNRCC)—Notification of Enforcement and Notification of Alleged Violations, Gomez Field Gathering Station, Fort Stockton, Texas. On October 28, 2002, the Company received a Notice of Enforcement for an alleged violation that a compliance certification during the period of December 30, 2000 through December 29, 2001 was not timely filed under its general operating permit requirements. The Company also received three Notices of Violations on October 18, 2002, for alleged failure to timely submit Permit Compliance Certifications for the period of April 2, 2000 through April 1, 2001 within thirty days and sixty days from the applicable deadlines, and a Notice of Violation for not submitting a deviation report, as required under Title V for the late submittals, for the period of April 2, 2000 through October 10, 2001. The Company has complied with all certification requirements with no penalties assessed.

Texas Natural Resource Conservation Commission (TNRCC)—Notification of Alleged Violations, Gomez Treating Plant, Texas. On December 5, 2001, the Company received notification of an alleged violation associated with compliance certifications for a treating plant owned by an unaffiliated company. The Company has contested the alleged violation on the basis that it never purchased this treating facility and the unaffiliated company had physically removed the facility in 1995. At this time, the Company is unable to quantify penalties or fines, if any, associated with this alleged violation.

        Retirement Plan.     The Company's retirement plan for its employees includes a fund, which allows them to invest in the Company's common stock. The fund manager, Fidelity Investments, purchases this stock in open market transactions. Under SEC rules, the stock purchased by the plan participants during a portion of 2001 and 2002 may be required to be registered by the Company. To resolve this issue, the Company intends to file a registration statement on Form S-3 with the SEC and offer to rescind or pay damages related to certain employee-initiated transactions during that period. Any stock acquired by the Company through this rescission offer will be treated as treasury stock. While the Company is unable to estimate the cost or results of the rescission offer, it does not expect the costs to have a material adverse effect on its financial position or results of operations.

        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 the Company's financial position or results of operations.

Commitments.

        Lease Commitments.     As a normal course of the Company's business operations, the Company enters into operating leases for office space, office equipment, communication equipment 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 two to ten years. The majority of the leases for compression have purchase options at various times throughout the primary terms of the agreements and has renewal provisions. Rental payments under operating leases have totaled $10.8 million, $3.1 million and $3.4 million in 2002, 2001 and 2000, respectively. Future operating lease payments by year under these leases are as follows (000s):

2003		$	12,902
2004			9,657
2005			9,227
2006			8,845
2007			8,029
Thereafter			13,026
	Total	$	61,686

        Firm Transportation Capacity.     The Company enters into firm transportation agreements with interstate pipeline companies as part of its marketing operations and to ensure that its equity production has access to downstream markets. These agreements have terms ranging from one month to fourteen years. Payments under these agreements have totaled $29.2 million, $8.8 million and $15.7 million in 2002, 2001 and 2000, respectively. Future payments by year under these agreements are as follows (000s):

2003		$	26,411
2004			25,000
2005			24,913
2006			24,732
2007			23,773
Thereafter			104,099
	Total	$	228,928

        Storage Capacity.     The Company enters into storage agreements with various third parties primarily as part of its marketing operations. To the extent that these contracts are in support of its marketing operations, the agreements are classified as derivatives in accordance with SFAS No. 133 and the difference between fair value and cost is included in income. Payments under these agreements have totaled $5.1 million, $3.9 million and $6.2 million in 2002, 2001 and 2000, respectively. As of December 31, 2002, the Company had contracts in place for approximately 20.2 Bcf of storage capacity at various third-party facilities. The associated contract periods have an average term of seventeen months. Future payments by year under these agreements are as follows (000s):

2003		$	5,240
2004			4,384
2005			3,193
2006			2,783
2007			2,582
Thereafter			10,451
	Total	$	28,633

NOTE 9—BUSINESS SEGMENTS AND RELATED INFORMATION

        The Company operates in four principal business segments, as follows: Gas 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.

        Gas Gathering, Processing and Treating.     In this segment, the Company connects producers' wells (including those of the Exploration and Production segment) to its gathering systems for delivery to its processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. In certain areas, where no processing is required, the Company gathers and compresses producers' gas and delivers it to pipelines. Except for volumes taken in kind by its producers, the Marketing segment sells the residue 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.

        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 65% of the Company's plant facilities' gross margins, or revenues at the plants less product purchases, for the month of December 2002 resulted from percentage-of-proceeds agreements in which it is typically responsible for the marketing of the gas and NGLs. The Company pays producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

        Approximately 21% of the Company's plant facilities' gross margins for the month of December 2002 resulted from contracts that are primarily fee-based from which it 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.

        Approximately 14% of the Company's plant facilities' gross margins for the month of December 2002 resulted from contracts that combine gathering, compression or processing fees with "keepwhole" arrangements or wellhead purchase contracts. Typically, the Company charges producers a gathering and compression fee based upon volume. In addition, 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 residue 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.

        Exploration and Production.     The activities of the Exploration and Production segment include the exploration and development of gas properties primarily in the Rocky Mountain basins 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.

        Marketing.     The Company's Marketing segment buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. The marketing of products purchased from third parties typically results in low operating margins relative to the sales price. In addition, this segment also markets gas and NGLs produced by the Company's gathering, processing, treating and production assets. Also included in this segment are its Canadian marketing operations (which are immaterial for separate presentation). In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. The Company sells its products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Its gas sales contracts have an average duration of 15 months. The Company records revenue on its gas and NGL marketing activities on a gross sales versus sales net of purchases basis as it obtains title to all of the gas and NGLs that it buys including third-party purchases, and bears the risk of loss and credit exposure on these transactions. Additionally, for its marketing activities the Company utilizes mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

        Transportation.     The Transportation segment reflects the operations of the Company's MIGC and MGTC pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas for the Company's Marketing segment and other 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 segments' firm capacity contracts range in duration from one month to six years.

        The following table sets forth the Company's segment information as of and for the three years ended December 31, 2002, 2001 and 2000 (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.

			Gas Gathering and Processing			Exploration and Production			Marketing			Transportation			Corporate			Eliminating Entries			Total
Year Ended December 31, 2002
Revenues from unaffiliated customers
	Sale of gas		$	2,155		$	1,497		$	2,090,480		$	1,252		$	—		$	—		$	2,095,384
	Sale of natural gas liquids			17			—			317,927			—									317,944
	Equity hedges:
		Residue		3,238			24,846			—			—			—			—			28,084
		Liquids		(8,247	)		—			—			—			—			—			(8,247	)
	Gathering, processing and transportation revenue			57,298			—			—			8,303			—			—			65,601
Total revenues from unaffiliated				54,461			26,343			2,408,407			9,555			—			—			2,498,766
Inter-segment sales				638,739			112,943			23,657			15,794			54			(791,187	)		—
Non-cash change in fair value of derivatives				(233	)		589			(14,144	)		—			—			—			(13,788	)
Interest income				—			43			10			1			8,803			(8,612	)		245
Other, net				2,843			45			6			(567	)		(415	)		2,563			4,475
Total revenues				695,810			139,963			2,417,936			24,783			8,442			(797,236	)		2,489,698
Product purchases				533,515			3,080			2,380,446			—			—			(759,862	)		2,157,179
Plant operating and transportation expense				73,878			—			—			9,068			—			(1,416	)		81,530
Oil and gas exploration and production expense				—			63,149			—			—			—			(29,142	)		34,007
Earnings from equity investments				(4,453	)		—			—			—			—			—			(4,453	)
Operating profit				92,870			73,734			37,490			15,715			8,442			(6,816	)		221,435
Depreciation, depletion and amortization				39,792			28,937			157			1,675			6,444			—			77,005
Selling and administrative expense				15,836			9,745			7,309			2,938			—			—			35,828
(Gain) loss from sale of assets				1,102			(323	)		—			476			267			(574	)		948
Interest expense				—			—			—			—			26,951			—			26,951
Segment profit			$	36,140		$	35,375		$	30,024		$	10,626		$	(25,220	)	$	(6,242	)	$	80,703
Identifiable assets
	Other allocated assets		$	19,457		$	3,429		$	117,167		$	1,064		$	279,473		$	(52,001	)	$	368,589
	Investment in others			2,839			—			—			3,802			55,509			(33,022	)		29,128
	Capital assets			587,244			221,160			1,672			42,077			52,267			7			904,427
Total identifiable assets			$	609,540		$	224,589		$	118,839		$	46,943		$	387,249		$	(85,016	)	$	1,302,144

			Gas Gathering and Processing			Exploration and Production			Marketing		Transportation		Corporate			Eliminating Entries			Total
Year Ended December 31, 2001
Revenues from unaffiliated customers
	Sale of gas		$	3,180		$	2,027		$	2,833,369	$	1,390	$	—		$	—		$	2,839,966
	Sale of natural gas liquids			(156	)		—			421,723		—		—			(6	)		421,561
	Equity hedges:
		Residue		7,833			1,298			—		—		—			—			9,131
		Liquids		2,521			—			—		—		—			—			2,521
	Gathering, processing and transportation revenue			48,175			—			—		7,187		36			—			55,398
Total revenues from unaffiliated				61,553			3,325			3,255,092		8,577		36			(6	)		3,328,577
Inter-segment sales				816,125			113,022			29,897		17,103		(545	)		(975,602	)		—
Non-cash change in fair value of derivatives				(208	)		188			19,926		—		—			—			19,906
Interest income				1			12			—		1		13,683			(12,860	)		836
Other, net				4,031			31			17		—		(237	)		—			3,843
Total revenues				881,502			116,578			3,304,932		25,681		12,937			(988,468	)		3,353,162
Product purchases				678,985			2,789			3,254,902		—		195			(949,921	)		2,986,950
Plant operating and transportation expense				68,473			117			—		9,213		(204	)		(2,066	)		75,533
Oil and gas exploration and production expense				—			49,277			—		—		—			(21,750	)		27,527
Earnings from equity investments				(1,790	)		—			—		—		—			—			(1,790	)
Operating profit				135,834			64,395			50,030		16,468		12,946			(14,731	)		264,942
Depreciation, depletion and amortization				39,141			17,692			161		1,646		5,522			—			64,162
Selling and administrative expense				16,108			7,197			8,911		2,056		—			—			34,272
Gain from sale of assets				(11,118	)		(326	)		—		511		185			—			(10,748	)
Interest expense				—			—			—		—		25,130			—			25,130
Segment profit			$	91,703		$	39,832		$	40,958	$	12,255	$	(17,891	)	$	(14,731	)	$	152,126
Identifiable assets
	Other allocated assets		$	4,142		$	3,724		$	131,705	$	1,078	$	290,239		$	(63,115	)	$	367,773
	Investment in others			1,806			—			—		3,453		39,551			(34,531	)		10,279
	Capital assets			613,203			178,572			1,830		43,452		52,833			—			889,890
Total identifiable assets			$	619,151		$	182,296		$	133,535	$	47,983	$	382,623		$	(97,646	)	$	1,267,942

			Gas Gathering and Processing			Exploration and Production			Marketing			Transportation		Corporate			Eliminating Entries			Total
Year Ended December 31, 2000
Revenues from unaffiliated customers
	Sale of gas		$	368		$	39		$	2,659,564		$	1,114	$	—		$	—		$	2,661,085
	Sale of natural gas liquids			—			—			596,793			—		—			(9	)		596,784
	Equity hedges:
		Residue		(6,969	)		(26,064	)		—			—		—			—			(33,033	)
		Liquids		(5,852	)		—			—			—		—			—			(5,852	)
	Gathering, processing and transportation revenue			45,613			—			—			7,506		37			—			53,156
Total revenues from unaffiliated				33,160			(26,025	)		3,256,357			8,620		37			(9	)		3,272,140
Inter-segment sales				776,264			84,972			94,858			16,484		44			(972,622	)		—
Non-cash change in fair value of derivatives				—			—			—			—		—			—			—
Interest income				98			6			27			—		27,505			(26,987	)		649
Other, net				7,191			137			(65	)		—		—			39			7,302
Total revenues				816,713			59,090			3,351,177			25,104		27,586			(999,579	)		3,280,091
Product purchases				616,594			1,268			3,331,634			—		(189	)		(963,806	)		2,985,501
Plant operating and transportation expense				63,621			376			69			7,802		(264	)		(1,712	)		69,892
Oil and gas exploration and production expense				—			28,645			—			—		—			(9,124	)		19,521
Earnings from equity investments				(1,897	)		—			—			—		—			—			(1,897	)
Operating profit				138,395			28,801			19,474			17,302		28,039			(24,937	)		207,074
Depreciation, depletion and amortization				35,010			15,435			161			1,676		5,668			(31	)		57,919
Selling and administrative expense				20,298			5,058			6,440			1,921		—			—			33,717
Gain from sale of assets				(3,800	)		(369	)		8			—		(5,245	)		—			(9,406	)
Interest expense				—			—			—			—		33,460			—			33,460
Segment profit			$	86,887		$	8,677		$	12,865		$	13,705	$	(5,844	)	$	(24,906	)	$	91,384
Identifiable assets
	Other allocated assets		$	30,950		$	4,299		$	113,249		$	1,026	$	492,307		$	(9,091	)	$	632,740
	Investment in others			1,176			—			—			4,201		136			154			5,667
	Capital assets			571,122			125,853			1,991			43,110		50,945			1			793,022
Total identifiable assets			$	603,248		$	130,152		$	115,240		$	48,337	$	543,388		$	(8,936	)	$	1,431,429

NOTE 10—EMPLOYEE BENEFIT PLANS

        Retirement Plan.     A discretionary retirement plan (a defined contribution plan) exists for all Company employees meeting certain service requirements. The Company may make annual discretionary contributions to the plan as determined by the board of directors and, during 2000, provided for a match of 50% of employee contributions on the first 4% of employee compensation contributed. Effective January 2001, the match of employee contributions has been increased to a sliding scale of 60% to 100% of the first 5% of employee compensation based upon years of service. Contributions are made to mutual funds and to purchase Company stock for which Fidelity Management Trust Company acts as trustee. The discretionary contributions made by the Company were $1.9 million, $2.3 million and $2.3 million, for the years ended December 31, 2002, 2001 and 2000, respectively. The matching contributions were approximately $1.3 million, $1.3 million and $470,000 for the years ended December 31, 2002, 2001 and 2000, respectively.

        Key Employees' Incentive Stock Option Plan and 1987 Non-Employee Directors Stock Option Plan.     Effective April 1987, the board of directors of the Company adopted a Key Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee Director Stock Option Plan ("1987 Directors Plan") that authorized the granting of options to purchase 250,000 and 20,000 shares of the Company's Common Stock, respectively. Each of these plans has terminated. The Company loaned to certain employees, an amount sufficient to exercise their options under these plans. The loan and accrued interest will be forgiven if the employee is continually employed by the Company and upon a resolution of the board of directors. As of December 31, 2002 and 2001, loans related to 27,500 and 75,000 shares of Common Stock totaling $295,000 and $803,000, respectively, were outstanding under these terms.

        1999 Non-Employee Directors Stock Option Plan.     Effective March 1999, the board of directors of the Company adopted a 1999 Non-Employee Directors' Stock Option Plan ("1999 Directors Plan") that authorized the granting of options to purchase 15,000 shares of the Company's Common Stock. During 1999, the board approved grants totaling 15,000 options to several board members. Under this plan, each of these options becomes exercisable as to 33¹/3% of the shares covered by it on each anniversary from the date of grant. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.

        1993, 1997 and 1999 Stock Option Plans.     The 1993 Stock Option Plan ("1993 Plan"), the 1997 Stock Option Plan ("1997 Plan"), and the 1999 Stock Option Plan ("1999 Plan") became effective on March 29, 1993, May 21, 1997, and May 21, 1999, respectively, after approvals by the Company's stockholders. Each plan is intended to be an incentive stock option plan in accordance with the provisions of Section 422 of the Internal Revenue Code of 1986, as amended. The Company has reserved 1,000,000 shares of Common Stock for issuance upon exercise of options under each of the 1993 Plan and the 1997 Plan and 750,000 shares of Common Stock for issuance upon exercise of options under the 1999 Plan. The 1993 Plan, the 1997 Plan and the 1999 Plan will terminate on the earlier of March 29, 2003, May 21, 2007 and May 21, 2009, respectively, or the date on which all options granted under each of the plans have been exercised in full. Although options covering 637,818 shares remain to be granted under the 1993 and 1997 Stock Option Plans, no further options will be granted under either plan.

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

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

        2002 Non-Employee Directors Stock Option Plan.     Effective May 2002, the shareholders approved the 2002 Non-Employee Directors' Stock Option Plan ("2002 Directors Plan") that authorized the granting of options to purchase 110,000 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 our board. Under this plan, a newly elected non-employee director will be granted 5,000 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 our annual meeting to each non-employee director of 2,000 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. During 2002, a total of 18,000 options were granted under this plan.

        2002 Stock Option Plan.     Effective May 2002, the shareholders approved the 2002 Stock Incentive Plan ("2002 Plan") that authorized the granting of options to purchase 1,250,000 shares of the Company's common stock. No employee may be granted more than 125,000 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 earlier of May 17, 2012 or the date on which all options granted under the plan have been exercised in full. During 2002, a total of 187,997 options were granted under this plan.

        Under each of the 1993, 1997, 1999 and 2002 plans, the board of directors of the Company determines and designates from time to time those employees of the Company to whom options are to be granted. If any option terminates or expires prior to being exercised, the shares relating to such option are released and may be subject to re-issuance pursuant to a new option. The board of directors has the right to, among other things, fix the method by which the price is determined and the terms and conditions for the grant or exercise of any option. The purchase price of the stock under each option shall be the average closing price for the ten days prior to the grant. Under the 1993 Plan, options granted vest 20% each year on the anniversary of the date of grant. Under the 1997, 1999 and 2002 Plans, the board of directors has the authority to set the vesting schedule from 20% per year to 33¹/3% per year. Under each of the plans, the employee must exercise the option within five years of the date each portion vests.

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

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

		Per Share Price Range		1999 Directors Plan	1993 Plan	1997 Plan	1999 Plan	Chief Executive Officer's Plan	2002 Stock Incentive Plan	2002 Non-Employee Director's Plan
Exercisable:
	December 31, 2002	$	0.01-5.00	—	—	21,071	—	—	—	—
		$	5.01-10.00	8,350	—	70,334	—	—	—	—
		$	10.01-15.00	—	5,474	33,600	14,446	—	—	—
		$	15.01-20.00	—	37,806	34,400	3,036	—	—	—
		$	20.01-25.00	—	5,816	—	31,975	—	—	—
		$	25.01-30.00	—	—	—	1,667	75,000	—	—
		$	30.01-35.00	—	4,289	—	11,441	—	—	—
		$	35.01-40.00	—	—	—	58,800	—	—	—
			TOTAL	8,350	53,385	159,405	121,365	75,000	—	—
	December 31, 2001	$	0.01-5.00	—	—	40,350	—	—	—	—
		$	5.01-10.00	7,789	—	86,445	—	—	—	—
		$	10.01-15.00	—	125,201	50,400	12,223	—	—	—
		$	15.01-20.00	—	18,358	34,440	2,438	—	—	—
		$	20.01-25.00	—	52,184	—	24,176	—	—	—
		$	25.01-30.00	—	—	—	—	—	—	—
		$	30.01-35.00	—	14,377	—	—	—	—	—
		$	35.01-40.00	—	—	—	—	—	—	—
			TOTAL	7,789	210,120	211,635	38,837	—	—	—
	December 31, 2000	$	0.01-5.00	—	—	20,111	—	—	—	—
		$	5.01-10.00	1,683	—	32,000	—	—	—	—
		$	10.01-15.00	—	176,503	17,520	8,888	—	—	—
		$	15.01-20.00	—	99,029	32,280	2,367	—	—	—
		$	20.01-25.00	—	21,138	—	—	—	—	—
		$	25.01-30.00	—	10,176	—	—	—	—	—
		$	30.01-35.00	—	82,960	—	—	—	—	—
		$	35.01-40.00	—	—	—	—	—	—	—
			TOTAL	1,683	389,806	101,911	11,255	—	—	—
Available for Grant:
	December 31, 2002		—	—	—	—	—	—	1,062,003	92,000
	December 31, 2001		—	—	—	—	287,634	—	—	—
	December 31, 2000		—	—	—	—	608,934	—	—	—

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

		Per Share Price Range		1999 Directors Plan		1993 Plan		1997 Plan		1999 Plan		Chief Executive Officer's Plan	2002 Stock Incentive Plan	2002 Non-Employee Director's Plan
Balance 12/31/99				15,000		565,874		646,700		35,266
	Granted	$	12.58-23.45	—		—		—		115,300		—	—	—
	Exercised	$	4.59-20.69	(3,317	)	(59,621	)	(136,722	)	(100	)	—	—	—
	Forfeited or canceled	$	4.59-35.00	—		(38,232	)	(8,601	)	(9,500	)	—	—	—
Balance 12/31/00				11,683		468,021		501,377		140,966		—	—	—
	Granted	$	25.01-36.34	—		—		—		413,200		300,000	—	—
	Exercised	$	4.59-35.00	—		(201,940	)	(150,056	)	(16,740	)	—	—	—
	Forfeited or canceled	$	4.59-36.34	—		(37,891	)	(2,501	)	(19,600	)	—	—	—
Balance 12/31/01				11,683		228,190		348,820		517,286		300,000	—	—
	Granted	$	32.95-33.45	—		—		—		170,000		—	187,997	18,000
	Exercised	$	4.59-35.00	(3,333	)	(161,878	)	(177,315	)	(41,373	)	—	—	—
	Forfeited or canceled	$	4.59-36.34	—		(11,285	)	(12,100	)	(15,070	)	—	—	—
Balance 12/31/02				8,350		55,027		159,405		631,383		300,000	187,997	18,000
Weighted-average remaining contractual life (in years)				3.9		0.3		3.9		5.3		6.3	6.8	6.8

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

		1999 Directors Plan			1993 Plan			1997 Plan			1999 Plan			Chief Executive Officer's Plan		2002 Stock Incentive Plan		2002 Non-Employee Director's Plan
Balance 12/31/99		$	5.51		$	19.54		$	7.72		$	13.58		$	—	$	—	$	—
	Granted		—			—			—			23.11			—		—		—
	Exercised		(5.51	)		(16.17	)		(7.33	)		(16.21	)		—		—		—
	Forfeited or canceled		—			(26.97	)		(8.66	)		(22.25	)		—		—		—
Balance 12/31/00			5.51			19.35			7.81			20.79			—		—		—
	Granted		—			—			—			34.72			25.01		—		—
	Exercised		—			(19.55	)		(7.22	)		(18.30	)		—		—		—
	Forfeited or canceled		—			(25.50	)		(4.59	)		(29.76	)		—		—		—
Balance 12/31/01			5.51			18.15			8.08			31.61			25.01		—		—
	Granted		—			—			—			32.95			—		32.98		37.82
	Exercised		(5.51	)		(15.97	)		(6.75	)		(22.50	)		—		—		—
	Forfeited or canceled		—			(35.00	)		(5.92	)		(26.46	)		—		—		—
Balance 12/31/02		$	5.51		$	19.73		$	9.73		$	32.68		$	25.01	$	32.98	$	37.82

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

        Costs.     The following tables set forth capitalized costs at December 31, 2002, 2001 and 2000 and costs incurred for oil and gas producing activities for the years ended December 31, 2002, 2001 and 2000 (000s):

		2002			2001			2000
Capitalized costs:
	Proved properties	$	239,579		$	194,596		$	119,124
	Unproved properties		64,451			40,137			46,890
Total			304,030			234,733			166,014
	Less accumulated depreciation and depletion		(79,050	)		(53,359	)		(36,367	)
Net capitalized costs		$	224,980		$	181,374		$	129,647
Costs incurred:
Acquisition of properties
	Proved	$	426		$	1,624		$	1,571
	Unproved		2,770			5,332			7,203
Development costs			48,648			63,263			35,807
Exploration costs			22,547			2,141			8,397
Total costs incurred		$	74,391		$	72,360		$	52,978

        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, 2002, 2001 and 2000 are as follows (000s):

			2002			2001			2000
Revenues from sale of oil and gas:
	Sales		$	2,227		$	4,517		$	4,658
	Transfers			112,137			110,532			80,353
		Total		114,364			115,049			85,011
Production costs				(65,536	)		(49,421	)		(27,108	)
Exploration costs				(3,543	)		(3,234	)		(2,213	)
Depreciation, depletion and amortization				(25,691	)		(17,175	)		(13,423	)
Income tax expense				(7,558	)		(15,827	)		(14,793	)
Results of operations			$	12,036		$	29,392		$	27,474

        Reserve Quantity Information.     Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations.

        The following table sets forth information for the years ended December 31, 2002, 2001 and 2000 with respect to changes in the Company's proved developed and undeveloped reserves, all of which are in the United States.

		Natural Gas (MMcf)		Crude Oil (MBbls)
Proved reserves:
	December 31, 1999	271,818		329
	Revisions of previous estimates	(11,889	)	(194	)
	Extensions and discoveries	176,584		332
	(Sales) Purchases of reserves in place	—		—
	Production	(28,019	)	(28	)
	December 31, 2000	408,494		439
	Revisions of previous estimates	(18,415	)	(110	)
	Extensions and discoveries	115,672		377
	(Sales) Purchases of reserves in place	—		—
	Production	(35,514	)	(45	)
	December 31, 2001	470,237		661
	Revisions of previous estimates	(88,371	)	105
	Extensions and discoveries	246,700		500
	(Sales) Purchases of reserves in place	(500	)	—
	Production	(47,401	)	(53	)
	December 31, 2002	580,665		1,213
	Proved developed reserves, included above:
	December 31, 1999	106,626		161
	December 31, 2000	208,218		147
	December 31, 2001	252,266		262
	December 31, 2002	265,300		400

        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.

        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, 2002, 2001 and 1999 is as follows (000s):

	2002			2001			2000
Future cash inflows	$	1,587,891		$	691,188		$	2,682,435
Future production costs		(463,471	)		(210,242	)		(462,065	)
Future development costs		(193,255	)		(110,365	)		(87,251	)
Future income tax expense		(305,263	)		(108,270	)		(732,327	)
Future net cash flows		625,902			262,311			1,400,792
10% annual discount for estimated timing of cash flows		(265,250	)		(90,941	)		(432,881	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	360,652		$	171,370		$	967,911

        Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 2002, 2001 and 2000 are as follows (000s):

		2002			2001			2000
January 1		$	171,370		$	967,911		$	112,927
	Sales and transfers of oil and gas produced, net of production costs		(50,828	)		(65,628	)		(57,903	)
	Net changes in prices and production costs related to future production		263,448			(1,349,674	)		768,840
	Development costs incurred during the period		40,753			50,494			35,807
	Changes in estimated future development costs		(42,869	)		(37,115	)		(21,369	)
	Changes in extensions and discoveries		148,114			57,300			640,501
	Revisions of previous quantity estimates		(87,705	)		(34,596	)		(64,710	)
	Purchases (sales) of reserves in place		(586	)		—			—
	Accretion of discount		24,118			147,393			15,706
	Net change in income taxes		(105,163	)		435,285			(461,888	)
December 31		$	360,652		$	171,370		$	967,911

NOTE 12—QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):

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

		Operating Revenues		Gross Profit(a)		Net Income		Earnings Per Share of Common Stock		Earnings Per Share of Common Stock— Assuming Dilution
2002 quarter ended:
	March 31	$	615,915	$	27,954	$	8,000	$	.18	$	.18
	June 30		614,122		40,466		13,766		.35		.34
	September 30		614,089		38,122		13,387		.34		.34
	December 31		645,572		37,888		15,436		.38		.37
		$	2,489,698	$	144,430	$	50,589	$	1.25	$	1.23
2001 quarter ended:
	March 31	$	1,196,834	$	69,556	$	40,590	$	1.17	$	1.08
	June 30		886,672		59,853		29,453		.82		.77
	September 30		670,521		37,687		14,773		.37		.36
	December 31		599,135		33,684		10,821		.23		.22
		$	3,353,162	$	200,780	$	95,637	$	2.59	$	2.48	(b)

(a)

Excludes selling and administrative, interest and income tax expenses, (gains) or losses on sale of assets, and extraordinary charges for early extinguishment of debt.

(b)

The sum of the quarterly calculations of earnings per share of common stock—assuming dilution do not total to the annual amount due to the inclusion of differing common stock equivalents in the various quarters and in the year as whole.

NOTE 13—GUARANTOR AND NON-GUARANTOR SUBSIDIARIES:

        The Company's payment obligations under its Revolving Credit Facility, its Master Shelf Agreement and its Senior Subordinated Notes (collectively, the "Financing Facilities") are fully and unconditionally guaranteed by its significant subsidiaries to the extent allowed by applicable law. These guarantees are joint and several and in the case of the Senior Subordinated Notes, are subordinated in right of payment to senior debt of the guarantors.

        During the years ended December 31, 2002 and 2001, the guarantors of the Company's payment obligations under its Financing Facilities were Lance Oil & Gas Company, Inc., Western Gas Resources-Texas, Inc., Mountain Gas Resources, Inc., MIGC, Inc., MGTC, Inc. and Western Gas Wyoming, L.L.C., (collectively, the "Guarantor Subsidiaries"). During the year ended December 31, 2000, in addition to the Guarantor Subsidiaries, Pinnacle Gas Treating, Inc. and Western Gas Resources-Oklahoma, Inc. were also guarantors.

        The Company's subsidiaries that did not guarantee the Company's payment obligations under its Financing Facilities during the years ended December 31, 2002, 2001 and 2000 included Western Power Services, Inc., Western Gas Resources-Westana, Inc. and WGR Canada, Inc. (collectively, the "Non-Guarantor Subsidiaries").

        Presented below is condensed consolidating financial information for Western Gas Resources, Inc. (the "Parent Company"), the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries. Balance sheet data are presented as of December 31, 2002 and 2001. The Statement of Operations and Statement of Cash Flows data are presented for the years ended December 31, 2002, 2001 and 2000.

        For purposes of the following tables, the Parent Company's investments in its subsidiaries are accounted for using the equity method of accounting. Net income of Guarantor and Non-Guarantor Subsidiaries is, therefore, reflected in the Parent Company column under Earnings from equity investments. Selling and administrative expense and Provision for income taxes are primarily reflected in the Parent Company column. The Consolidating entries eliminate the investments in the subsidiaries and other inter-company transactions for consolidated reporting purposes.

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2002

			Parent Company	Guarantor Subsidiaries		Non- Guarantor Subsidiaries	Consolidating Entries		TOTAL
ASSETS
Current assets:
	Cash and cash equivalents		7,138	128		46	—		7,312
	Trade accounts receivable, net		256,508	14,013		10,382	(27,316	)	253,587
	Inventory		36,406	—		7,076	—		43,482
	Assets held for sale		3,250	—		—	—		3,250
	Assets from price risk management activities		34,873	—		—	—		34,873
	Other		29,847	(2,675	)	572	—		27,744
		Total current assets	368,022	11,466		18,076	(27,316	)	370,248
Total property and equipment, net			348,937	466,538		51,271	(100	)	866,646
Other assets:
	Gas purchase contracts, net		7,722	23,202		—	—		30,924
	Assets from price risk management activities		406	—		—	—		406
	Other assets		58,864	486		5	(51,051	)	8,304
	Investments in subsidiaries		444,823	22,777		2,839	(444,823	)	25,616
		Total other assets	511,815	46,465		2,844	(495,874	)	65,250
Total assets			1,228,774	524,469		72,191	(523,290	)	1,302,144
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		211,220	45,003		15,078	(28,314	)	242,987
	Accrued expenses		40,091	9,472		1,946	—		51,509
	Liabilities from price risk management activities		34,811	—		—	—		34,811
	Dividends payable		3,464	—		—	—		3,464
		Total current liabilities	289,586	54,475		17,024	(28,314	)	332,771
Long-term debt			359,933	—		—	—		359,933
Other long-term liabilities			1,713	44,967		6,084	(51,051	)	1,713
Liabilities from price risk management activities			406	—		—	—		406
Deferred income taxes payable			99,642	29,287		—	(4,676	)	124,253
Total liabilities			751,280	128,729		23,108	(84,041	)	819,076
Total stockholders' equity			477,494	395,740		49,083	(439,249	)	483,068
Total liabilities and stockholders' equity			1,228,774	524,469		72,191	(523,290	)	1,302,144

Supplemental Condensed Consolidating Statement of Operations
For the year ended December 31, 2002

			Parent Company		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Entries		TOTAL
Total revenues			2,943,035		213,484		130,457		(797,278	)	2,489,698
Costs and expenses:
	Product purchases		2,758,546		39,773		118,164		(759,304	)	2,157,179
	Plant operating expense		54,703		25,968		2,834		(1,975	)	81,530
	Oil and gas exploration and production costs		1,290		61,859		—		(29,142	)	34,007
	Depreciation, depletion and amortization		31,323		42,739		2,943		—		77,005
	Selling and administrative expense		33,066		2,562		254		(54	)	35,828
	(Gain) loss on sale of assets		1,095		157		272		(576	)	948
	Earnings from equity investments		(41,206	)	(2,259	)	(2,194	)	41,206		(4,453	)
	Interest expense		26,883		8,548		132		(8,612	)	26,951
		Total costs and expenses	2,865,700		179,347		122,405		(758,457	)	2,408,995
Income before income taxes			77,335		34,137		8,052		(38,821	)	80,703
Total provision for income taxes			29,131		—		983		—		30,114
Net income			48,204		34,137		7,069		(38,821	)	50,589

Supplemental Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2002

			Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			TOTAL
Net cash provided by operating activities			$	24,124		$	96,812		$	10,199		$	1		$	131,136
Cash flows from investing activities:
	Purchases of property and equipment, including acquisitions			(36,516	)		(84,018	)		(7,525	)		2,459			(125,600	)
	Proceeds from the disposition of property and equipment			33,060			4,189			75			(2,459	)		34,865
	Other net cash used in investing activities			5,195			(15,022	)		(5,209	)		(1	)		(15,037	)
		Net cash used in investing activities		1,739			(94,851	)		(12,659	)		(1	)		(105,772	)
Cash flows from financing activities:
	Payments on revolving credit facility			(992,945	)		—			—			—			(992,945	)
	Borrowings under revolving credit facility			994,545			—			—			—			994,545
	Dividends paid			(15,107	)		—			—			—			(15,107	)
	Other net cash used in financing activities			(14,577	)		—			—			—			(14,577	)
		Net cash used in financing activities		(28,084	)		—			—			—			(28,084	)
Net decrease in cash and cash equivalents				(2,221	)		1,961			(2,460	)		—			(2,720	)
Cash and cash equivalents at beginning of year				9,359			(1,833	)		2,506			—			10,032
Cash and cash equivalents at end of year			$	7,138		$	128		$	46		$	—		$	7,312

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2001

			Parent Company	Guarantor Subsidiaries		Non- Guarantor Subsidiaries	Consolidating Entries		TOTAL
ASSETS
Current assets:
	Cash and cash equivalents		9,359	(1,833	)	2,506	—		10,032
	Trade accounts receivable, net		227,738	9,550		15,039	(31,790	)	220,537
	Inventory		42,194	—		8,579	—		50,773
	Assets held for sale		—	—		—	—		—
	Assets from price risk management activities		66,271	—		—	—		66,271
	Other		15,246	2,865		239	—		18,350
		Total current assets	360,808	10,582		26,363	(31,790	)	365,963
Total property and equipment, net			376,005	427,936		47,036	(2,670	)	848,307
Other assets:
	Gas purchase contracts, net		8,156	24,670		—	—		32,826
	Assets from price risk management activities		2,934	—		—	—		2,934
	Other assets		66,845	781		3	(56,833	)	10,796
	Investment in subsidiaries		404,215	5,496		1,620	(404,215	)	7,116
		Total other assets	482,150	30,947		1,623	(461,048	)	53,672
Total assets			1,218,963	469,465		75,022	(495,508	)	1,267,942
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		230,928	29,686		19,200	(19,606	)	260,208
	Accrued expenses		17,857	3,923		1,343	—		23,123
	Liabilities from price risk management activities		18,075	—		—	—		18,075
	Dividends payable		3,767	—		—	—		3,767
		Total current liabilities	270,627	33,609		20,543	(19,606	)	305,173
Long-term debt			366,667	—		—	—		366,667
Other long-term liabilities			2,284	44,967		11,866	(56,833	)	2,284
Liabilities from price risk management activities			1,720	—		—	—		1,720
Deferred income taxes payable			94,135	29,287		—	(4,676	)	118,746
Total liabilities			735,433	107,863		32,409	(81,115	)	794,590
Total stockholders' equity			483,530	361,602		42,613	(414,393	)	473,352
Total liabilities and stockholders' equity			1,218,963	469,465		75,022	(495,508	)	1,267,942

Supplemental Condensed Consolidating Statement of Operations
For the year ended December 31, 2001

			Parent Company		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Entries		TOTAL
Total revenues			3,909,286		238,063		192,463		(986,650	)	3,353,162
Costs and expenses:
	Product purchases		3,687,109		62,101		186,476		(948,736	)	2,986,950
	Plant operating expense		52,033		23,932		2,819		(3,251	)	75,533
	Oil and gas exploration and production costs		793		48,484		—		(21,750	)	27,527
	Depreciation, depletion and amortization		31,051		31,150		1,930		31		64,162
	Selling and administrative expense		27,676		6,356		293		(53	)	34,272
	(Gain) loss on sale of assets		226		(10,974	)	—		—		(10,748	)
	Earnings from equity investments		(62,747	)	(185	)	(1,605	)	62,747		(1,790	)
	Interest expense		21,750		14,054		488		(11,162	)	25,130
		Total costs and expenses	3,757,891		174,918		190,401		(922,174	)	3,201,036
Income before income taxes			151,395		63,145		2,062		(64,476	)	152,126
Total provision for income taxes			56,489		2,460		—		(2,460	)	56,489
Net income			94,906		60,685		2,062		(62,016	)	95,637

Supplemental Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2001

			Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			TOTAL
Net cash provided by operating activities			$	59,505		$	77,899		$	16,327		$	(464	)	$	153,267
Cash flows from investing activities:
	Purchases of property and equipment, including acquisitions			(38,174	)		(111,314	)		(14,489	)		—			(163,977	)
	Proceeds from the disposition of property and equipment			75			38,019			—			—			38,094
	Other net cash used in investing activities			(1,240	)		(5,310	)		312			464			(5,774	)
		Net cash used in investing activities		(39,339	)		(78,605	)		(14,177	)		464			(131,657	)
Cash flows from financing activities:
	Payments on revolving credit facility			(528,330	)		—			—			—			(528,330	)
	Borrowings under revolving credit facility			569,630			—			—			—			569,630
	Dividends paid			(16,846	)		—			—			—			(16,846	)
	Other net cash used in financing activities			(48,959	)		—			—			—			(48,959	)
		Net cash used in financing activities		(24,505	)		—			—			—			(24,505	)
Net decrease in cash and cash equivalents				(4,339	)		(706	)		2,150			—			(2,895	)
Cash and cash equivalents at beginning of year				13,698			(1,127	)		356			—			12,927
Cash and cash equivalents at end of year			$	9,359		$	(1,833	)	$	2,506		$	—		$	10,032

Supplemental Condensed Consolidating Statement of Operations
For the year ended December 31, 2000

			Parent Company		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Entries		TOTAL
Total revenues			3,882,985		286,899		161,031		(1,050,824	)	3,280,091
Costs and expenses:
	Product purchases		3,723,729		125,464		148,522		(1,012,214	)	2,985,501
	Plant operating expense		43,031		27,393		2,561		(3,093	)	69,892
	Oil and gas exploration and production costs		1,982		26,662		—		(9,123	)	19,521
	Depreciation, depletion and amortization		28,845		27,308		1,797		(31	)	57,919
	Selling and administrative expense		29,958		3,390		423		(54	)	33,717
	(Gain) loss on sale of assets		(9,085	)	(321	)	—		—		(9,406	)
	Earnings from equity investments		(60,560	)	—		(1,897	)	60,560		(1,897	)
	Interest expense		33,381		26,281		557		(26,759	)	33,460
		Total costs and expenses	3,791,281		236,177		151,963		(990,714	)	3,188,707
Income before income taxes			91,704		50,722		9,068		(60,110	)	91,384
Total provision for income taxes			33,501		(831	)	61		831		33,562
Net income			58,203		51,553		9,007		(60,941	)	57,822

Supplemental Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2000

			Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			TOTAL
Net cash provided by operating activities			$	80,522		$	48,672		$	(12,555	)	$	(377	)	$	116,262
Cash flows from investing activities:
	Purchases of property and equipment, including acquisitions			(41,837	)		(59,238	)		(7,492	)		31			(108,536	)
	Proceeds from the disposition of property and equipment			18,046			8,438			—			—			26,484
	Other net cash used in investing activities			(7,882	)		—			7,549			346			13
		Net cash used in investing activities		(31,673	)		(50,800	)		57			377			(82,039	)
Cash flows from financing activities:
	Payments on revolving credit facility			(1,392,286	)		—			—			—			(1,392,286	)
	Borrowings under revolving credit facility			1,399,736			—			—			—			1,399,736
	Dividends paid			(16,877	)		—			—			—			(16,877	)
	Other net cash used in financing activities			(25,931	)		—			—			—			(25,931	)
		Net cash used in financing activities		(35,358	)		—			—			—			(35,358	)
Net decrease in cash and cash equivalents				13,491			(2,128	)		(12,498	)		—			(1,135	)
Cash and cash equivalents at beginning of year				207			1,001			12,854			—			14,062
Cash and cash equivalents at end of year			$	13,698		$	(1,127	)	$	356		$	—		$	12,927

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

        None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted because the Company will file a definitive proxy statement (the "Proxy Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the Proxy Statement to be so filed for the Company's annual meeting of stockholders scheduled for May 16, 2003 and is hereby incorporated by reference.

ITEM 14. CONTROLS AND PROCEDURES

        Under the direction of the Chief Executive Officer and President and the Executive Vice President—Chief Financial Officer, we have reviewed and evaluated our disclosure controls and procedures and believe, as of the date of management's evaluation, that our disclosure controls and procedures are reasonably designed to be effective for the purposes for which they are intended. The review and evaluation was performed within 90 days prior to the filing of this report.

        There have not been any significant changes in our internal controls or any other factors that could significantly affect these controls subsequent to the date of management's evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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

(a)

The following documents are filed as part of this report:

(1)

Financial Statements:

Reference is made to page 41 for a list of all financial statements filed as a part of this report.

(2)

Financial Statement Schedules:

None required.

(3)

Exhibits:

        3.1  Certificate of Incorporation of Western Gas Resources, Inc. (Filed as exhibit 3.1 to Western Gas Resources, Inc.'s 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. (Filed as exhibit 3.2 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

        3.3  Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on February 12, 1999. (Filed as exhibit 12.1 to Western Gas Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 1999 and incorporated herein by reference).

        3.4  Amended and Restated Bylaws of Western Gas Resources, Inc., adopted by the Board of Directors on October 12, 2001 (Filed as exhibit 3.3 to Western Gas Resources, Inc., 10-Q dated September 30, 2001 and incorporated herein by reference).

        4.1  Western Gas Resources, Inc. Key Employees' Incentive Stock Option Plan. (Filed as exhibit 10.13 to Western Gas Resources, Inc.'s Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference).

        4.2  Certificate of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock of the Company. (Filed as exhibit 3.5 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-43077 dated November 14, 1991 and incorporated herein by reference).

        4.3  Certificate of Designation of $2.28 Cumulative Preferred Stock of the Company. (Filed as exhibit 3.6 to Western Gas Resources, Inc.'s Registration Statement of Form S-1, Registration No. 33-53786 dated November 12, 1992 and incorporated herein by reference).

        4.4  Second Amendment and First Restatement of Western Gas Processors, Ltd. Employees' Common Units Option Plan. (Filed as exhibit 10.6 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-43077 dated November 14, 1991 and incorporated herein by reference).

        4.5  Certificate of Designation of the $2.625 Cumulative Convertible Preferred Stock of the Company. (Filed under cover of Form 8-K dated February 24, 1994 and incorporated herein by reference).

        4.6  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. (Filed as exhibit 28 to Western Gas Resources, Inc.'s Form 10-Q for the three months ended June 30, 1999 and incorporated herein by reference).

        4.7  Rights Agreement, dated as of March 22, 2001 between Western Gas Resources, Inc., and Fleet National Bank as Rights Agent, including exhibits thereto (Filed as an exhibit to Form 8-A dated March 29, 2001 and incorporated herein by reference).

        4.8  Western Gas Resources, Inc., 1999 Stock Option Plan. (Filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-8, Registration No. 33-95255 dated January 24, 2000 and incorporated herein by reference).

        4.9  Western Gas Resources, Inc., Non-Employee Director Stock Option Plan. (Filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-8, Registration No. 33-95259 dated January 24, 2000 and incorporated herein by reference).

      4.10  Post Effective Amendment No. 1 to Form S-8 Registration Statement under 1999 Stock Option Plan for shares issued to certain employees dated May 23, 2001 and incorporated herein by reference.

      4.11  Stock Option Plan filed for Peter A. Dea on Form S-8 Registration Statement dated December 21, 2001, and incorporated herein by reference.

      4.12  Western Gas Resources, Inc., Retirement Plan registering 1,000,000 shares of common stock on Form S-8 Registration Statement dated August 14, 2002, and incorporated herein by reference.

      4.13  Western Gas Resources, Inc., 2002 Stock Incentive Plan registering 1,250,000 shares of common stock on Form S-8 Registration Statement dated March 7, 2003, and incorporated herein by reference.

      4.14  Western Gas Resources, Inc., 2002 Non-Employee Directors' Stock Option Plan registering 110,000 shares of common stock on Form S-8 Registration Statement dated March 7, 2003, and incorporated herein by reference.

      4.15  Western Gas Resources, Inc., Exchange Offer. (Filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-4, Registration No. 33-86881 dated September 10, 1999 and incorporated herein by reference).

      4.16  Western Gas Resources, Inc. First Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated October 19, 1999. (Filed as exhibit 4.10 to Western Gas Resources, Inc., 10-K for the year ended 12/31/01 and incorporated herein by reference).

      4.17  Western Gas Resources, Inc. Second Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated September 29, 2000. (Filed as exhibit 4.11 to Western Gas Resources, Inc., 10-K for the year ended 12/31/01 and incorporated herein by reference).

      4.18  Western Gas Resources, Inc. Third Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated January 3, 2001. (Filed as exhibit 4.12 to Western Gas Resources, Inc., 10-K for the year ended 12/31/01 and incorporated herein by reference).

      10.1  Restated Profit-Sharing Plan and Trust Agreement of Western Gas Resources, Inc. (Filed as exhibit 10.8 to Western Gas Resources, Inc.'s Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference).

      10.2  Registration Rights Agreement among Western Gas Resources, Inc., WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas Company and Sauvage Gas Service, Inc. (Filed as exhibit 10.14 to Western Gas Resources, Inc.'s Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference).

      10.3  Amendment No. 1 to Registration Rights Agreement 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. (Filed as exhibit 4.2 to Western Gas Resources, Inc.'s Form 10-Q for the quarter ended June 30, 1991 and incorporated herein by reference).

      10.4  Agreement to provide loans to exercise key employees' common stock options. (Filed as exhibit 10.26 to Western Gas Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 1991 and incorporated herein by reference).

      10.5  Form of revised Employment Agreement with exhibit thereto by and between Western Gas Resources, Inc., and its Executive Officers dated June 14, 2001 (Filed as exhibit 10.7 to Western Gas Resources, Inc., 10-Q dated June 30, 2001 and 10-Q dated September 30, 2001 and incorporated herein by reference).

      10.6  Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and between Western Gas Resources, Inc. and Prudential Company of America. (Filed as exhibit 10.49 to Western Gas Resources, Inc.'s Form 10-K for the year ended December 31, 1995 and incorporated herein by reference).

      10.7  Amended and Restated Note Purchase Agreement dated April 28, 1999 by and among Western Gas Resources, Inc. and the Purchasers identified therein. (Filed as exhibit 10.21 to Western Gas Resources, Inc.'s Form 10-Q for the three months ended March 31, 1999 and incorporated herein by reference).

      10.8  Offer to Acquire Notes dated February 12, 1999 by and between Western Gas Resources, Inc. and CIGNA Investments, Inc., Royal Maccabees Life Insurance Company, The Canada Life Assurance Company, and Canada Life Insurance Company of America, original Purchasers under the Note Purchase Agreement dated as of April 1, 1993 by and between Company and Purchasers for $50,000,000, 7.65% Senior Notes due April 30, 2003. (Filed as exhibit 12.3 in Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference).

      10.9  Offer to Acquire Notes dated February 12, 1999 by and between Western Gas Resources, Inc. and MONY Life Insurance Company, one of the original Purchasers under the Note Purchase Agreement dated as of November 29, 1995 by and between Company and Purchasers for $42,000,000, 8.02% Senior Notes due December 1, 2005. (Filed as exhibit 12.4 in Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference).

    10.10  Letter Amendment No. 2 dated March 31, 1999 to the Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company. (Filed as exhibit 10.22 in Western Gas Resources, Inc. Form 10-Q for the three months ended March 31, 1999 and incorporated herein by reference).

    10.11  Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders. (Filed as exhibit 10.20 in Western Gas Resources, Inc. Form 10-Q for the three months ended March 31, 1999 and incorporated herein by reference).

    10.12  Letter Amendment No. 3 dated June 1, 1999 to the Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company. (Filed as exhibit 10.14 to Western Gas Resources, Inc., 10-K for the year ended December 31, 2000 and incorporated herein by reference.)

    10.13  First Amendment dated June 10, 1999 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc. and NationsBank as Agent, and the Lenders. (Filed as exhibit 10.16 to Western Gas Resources, Inc., 10-K for the year ended 12/31/01 and incorporated herein by reference).

    10.14  Third Amendment dated April 27, 2000 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders. (Filed as exhibit 10.23 in Western Gas Resources, Inc. Form 10-Q for the three months ended March 31, 2000 and incorporated herein by reference).

    10.15  Limited Waiver, Consent, Release and Amendment No. 4 dated August 25, 2000 to the Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company. (Filed as exhibit 10.24 to Western Gas Resources, Inc., Form 10-Q for the nine months ended September 30, 2000 and is incorporated herein by reference).

    10.16  Letter Amendment No. 5 dated March 30, 2001 to Second Amended and Restated Master Shelf Agreement dated December 19, 1991 by and between Western Gas Resources, Inc., and The Prudential Insurance Company of America. (Filed as exhibit 10.25 to Western Gas Resources, Inc., 10-Q dated March 31, 2001 and incorporated herein by reference).

    10.17  Fourth Amendment dated August 25, 2000 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc. and NationsBank, as Agent, and the Lenders. (Filed as exhibit 10.25 to Western Gas Resources, Inc., Form 10-Q for the nine months ended September 30, 2000 and is incorporated herein by reference).

    10.18  Fifth Amendment dated November 22, 2000 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders. (Filed as exhibit 10.20 to Western Gas Resources, Inc., 10-K for the year ended 12/31/01 and incorporated herein by reference).

    10.19  Sixth Amendment dated April 26, 2001 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and NationsBank, as agent, and the Lenders. (Filed as exhibit 10.24 to Western Gas Resources, Inc., 10-Q dated March 31, 2001 and incorporated herein by reference).

    10.20  Limited Waiver, Consent, Release and Amendment No. 5 dated November 22, 2000 to the Second Amended and Restated Master Shelf Agreement by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company. (Filed as exhibit 10.21 to Western Gas Resources, Inc., 10-K for the year ended 12/31/01 and incorporated herein by reference).

    10.21  Intercreditor Agreement dated April 26, 2001 by and among Western Gas Resources, Inc., Bank of America, N.A., and The Prudential Insurance Company of America. (Filed as exhibit 10.26 to Western Gas Resources, Inc., 10-Q dated March 31, 2001 and incorporated herein by reference).

    10.22  Amendment to Employment Agreement by and between Western Gas Resources, Inc., and Lanny F. Outlaw, its Chief Executive Officer and President dated May 18, 2001. (Filed as exhibit 10.27 to Western Gas Resources, Inc., 10-Q dated June 30, 2001 and incorporated herein by reference).

    10.23  Consultation Agreement by and between Western Gas Resources, Inc., and Lanny F. Outlaw, its Chief Executive Officer and President dated November 1, 2001. (Filed as exhibit 10.27 to Western Gas Resources, Inc., 10-Q dated June 30, 2001 and incorporated herein by reference).

    10.24  Employment Agreement, as amended, dated October 15, 2001, Indemnification Agreement and Stock Option Agreement dated November 1, 2001 between Western Gas Resources, Inc., and Peter A. Dea. (Filed as exhibits to the Stock Option Plan for Peter A. Dea on Form S-8 Registration Statement dated December 2001, and incorporated herein by reference.)

    10.25  Seventh Amendment dated September 27, 2001 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and NationsBank, as agent, and the Lenders. (Filed as exhibit 10.25 to Western Gas Resources, Inc., 10-K for the year ended December 31, 2001 and incorporated by reference.)

    10.26  Eighth Amendment dated February 25, 2002 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A. (formerly NationsBank) as agent and the Lenders. (Filed as exhibit 10.26 to Western Gas Resources, Inc., 10-K for the year ended December 31, 2001 and incorporated by reference.)

    10.27  Ninth Amendment dated April 25, 2002 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A. (formerly NationsBank) as agent and the Lenders. (Filed as exhibit 10.16 to Western Gas Resources, Inc., 10-Q dated March 31, 2002 and incorporated by reference.)

    10.28  Tenth Amendment dated January 3, 2003 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A. (formerly NationsBank) as agent and the Lenders.

    10.29  Third Amended and Restated Master Shelf Agreement dated as of December 19, 1991 and effective as of January 13, 2002 by and between Western Gas Resources, Inc., and the Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc., and certain other Prudential Affiliates.

      11.1  Statement regarding computation of per share earnings.

          21    List of Subsidiaries of Western Gas Resources, Inc.

      23.1  Consent of PricewaterhouseCoopers LLP.

      23.2  Consent of Netherland, Sewell & Associates, Inc.

      99.1  Certification by Peter A. Dea, President and Chief Executive Officer, and William J. Krysiak, Executive Vice President—Chief Financial Officer required by Sarbanes-Oxley Act of 2002.

(b)

Reports on Form 8-K:

        A report on Form 8-K was filed on October 25, 2002 announcing the plaintiffs' filing of a complaint for declaratory relief in Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. v. Williams Production RMJ Company; Civil Action No. CO2-10-394, District Court, County of Sheridan Wyoming.

        A report on Form 8-K was furnished on November 13, 2002 providing an update to the Company's 2002 operational guidance.

        A report on Form 8-K was filed on November 26, 2002 announcing the redemption of all outstanding shares of the Company's $2.28 Cumulative Perpetual Preferred Stock and the de-listing with the New York Stock Exchange of that security.

        A report on Form 8-K was furnished on February 21, 2003 announcing the Company's 2002 Results of Operations.

        A report on Form 8-K was furnished on February 21, 2003 providing the Company's operational guidance for 2003.

(c)

Exhibits required by Item 601 of Regulation S-K. See (a)(3) above.

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado on March 21, 2003.

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

        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.

/s/  BRION G. WISE Brion G. Wise	Chairman of the Board	March 21, 2003
/s/  WALTER L. STONEHOCKER Walter L. Stonehocker	Vice Chairman of the Board	March 21, 2003
Bill M. Sanderson	Director
/s/  LANNY F. OUTLAW Lanny F. Outlaw	Director	March 21, 2003
/s/  RICHARD B. ROBINSON Richard B. Robinson	Director	March 21, 2003
/s/  DEAN PHILLIPS Dean Phillips	Director	March 21, 2003
/s/  WARD SAUVAGE Ward Sauvage	Director	March 21, 2003

/s/  JAMES A. SENTY James A. Senty	Director	March 21, 2003
/s/  JOSEPH E. REID Joseph E. Reid	Director	March 21, 2003
/s/  WILLIAM J. KRYSIAK William J. Krysiak	Executive Vice President—Chief Financial Officer (Principal Financial and Accounting Officer)	March 21, 2003

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Peter A. Dea, certify that:

1.

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

2.

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

3.

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

4.

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

a)

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

b)

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

c)

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

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

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

b)

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

6.

The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/  PETER A. DEA Peter A. Dea
Chief Executive Officer and President

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William J. Krysiak, certify that:

1.

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

2.

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

3.

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

4.

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

a)

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

b)

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

c)

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

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

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

b)

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

6.

The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/  WILLIAM J. KRYSIAK William J. Krysiak
Executive Vice President and Chief Financial Officer

EX-10.28

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Exhibit 10.28

TENTH AMENDMENT TO LOAN AGREEMENT AND
AMENDMENT TO INTERCREDITOR AGREEMENT

        THIS TENTH AMENDMENT TO LOAN AGREEMENT AND AMENDMENT TO INTERCREDITOR AGREEMENT (herein called this "Amendment") is made as of the 3rd day of January, 2003, by and among Western Gas Resources, Inc. ("Borrower"), Bank of America, N.A. ("Agent"), and the Lenders under the Loan Agreement referred to below.

W I T N E S S E T H:

        WHEREAS, Borrower, Agent, and Lenders have entered into that certain Loan Agreement dated as of April 29, 1999 (as amended, restated, or supplemented to the date hereof, the "Original Agreement"), for the purposes and consideration therein expressed, pursuant to which Lenders made and became obligated to make loans to Borrower as therein provided;

        WHEREAS, Borrower, Agent, and Lenders desire to amend the Original Agreement for the purposes described herein;

        WHEREAS, Borrower previously issued to The Prudential Insurance Company of America ("PICA") and Pruco Life Insurance Company ("PRUCO") those certain Senior Notes dated October 27, 1992, September 22, 1993, December 27, 1993, October 27, 1994, and July 28, 1995, pursuant to a Master Shelf Agreement dated as of December 19, 1991 by and between Borrower and PICA (as heretofore amended, supplemented or modified, the "Original Prudential Agreement");

        WHEREAS, Borrower is entering into a Third Amended and Restated Master Shelf Agreement dated as of December 19, 1991 (effective as of January 13, 2003) (the "Restated Prudential Agreement"), with PICA, PRUCO and Prudential Investment Management, Inc. ("Prudential"), amending and restating the Original Prudential Agreement, pursuant to which, among other things, the period during which senior notes may be issued thereunder is being extended and the facility size is being increased by $65,000,000 (allowing Borrower to issue an additional $65,000,000 in Debt Securities);

        WHEREAS, Agent, Lenders, and Prudential (as successor in interest to PICA) entered into that certain Intercreditor Agreement dated as of April 26, 2001 (the "Original Intercreditor Agreement"), to evidence their agreement with respect to certain payments that may be received by the Lenders and PICA under or in connection with the various guaranties executed by Related Persons in favor of the Lenders and Prudential;

        WHEREAS, Prudential is succeeding to all of PICA's rights and obligations under the Original Intercreditor Agreement;

        WHEREAS, Borrower desires that Majority Lenders consent to the Restated Master Shelf Agreement and the terms set forth therein; and

        WHEREAS, Agent, Lenders and Prudential desire to amend the Original Intercreditor Agreement on the terms set forth herein.

        NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.
Definitions and References

        § 1.1.    Defined Terms.    Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment. As used herein, the following terms shall have the following meanings:

"Amendment" means this Tenth Amendment to Loan Agreement and Amendment to Intercreditor Agreement.

"Intercreditor Agreement" means the Original Intercreditor Agreement as amended by this Amendment.

"Loan Agreement" means the Original Agreement as amended by this Amendment.

ARTICLE II.
Amendment

        § 2.1.    Definitions.

        (a)  The definition of "Debt Securities" in Section 1.1 of the Original Agreement is hereby amended in its entirety to read as follows:

"Debt Securities" means collectively those senior notes dated October 27, 1992, September 22, 1993, December 27, 1993, October 27, 1994, July 28, 1995, and all other senior notes issued by Borrower pursuant to that certain Third Amended and Restated Master Shelf Agreement effective as of January 13, 2003, between Borrower and The Prudential Insurance Company of America, Prudential Investment Management, Inc., Pruco Life Insurance Company and certain Prudential Affiliates, their successors and assigns, as amended, supplement, modified and restated from time to time (herein called the "Shelf Agreement")."

        (b)  The following definitions are hereby added to Section 1.1 of the Original Agreement, in alphabetical order, to read as follows:

"Assignment and Acceptance" means an assignment and acceptance in substantially the same form as Exhibit G."

"Tranche A Lenders" means Lenders designated as Tranche A Lenders on the Lenders Schedule."

"Tranche A Majority Lenders" means, at the time in question, two or more Tranche A Lenders collectively having at least a 66²/3% Tranche A Percentage Share."

"Tranche A Percentage Share" means, with respect to any Tranche A Lender (a) when used in Sections 2.1 or 2.9, in any Notice of Borrowing or when no Tranche A Loans are outstanding hereunder, the percentage set forth opposite such Tranche A Lender's name on Schedule 3 attached hereto, and (b) when used otherwise, the percentage equal to the percentage obtained by dividing (i) the sum of the unpaid principal balance of such Tranche A Lender's Tranche A Loans at the time in question, by (ii) the aggregate unpaid principal balance of all Tranche A Loans at such time."

"Tranche B Lenders" means Lenders designated as Tranche B Lenders on the Lenders Schedule."

"Tranche B Majority Lenders" means, at the time in question, two or more Tranche B Lenders collectively having at least a 66²/3% Tranche B Percentage Share."

"Tranche B Percentage Share" means, with respect to any Tranche B Lender (a) when used in Sections 2.1 or 2.9, in any Notice of Borrowing or when no Tranche B Loans are outstanding hereunder, the percentage set forth opposite such Tranche B Lender's name on Schedule 3 attached hereto, and (b) when used otherwise, the percentage equal to the percentage obtained by dividing (i) the sum of the unpaid principal balance of such Tranche B Lender's Tranche B Loans at the time in question plus the Matured LC Obligations which such Tranche B Lender has funded pursuant to Section 3.2(b) plus that portion of the amount which Tranche B Lenders might be called upon to advance under all LCs then outstanding that such Tranche B Lender would be obligated to fund under Section 3.2(b), by (ii) the aggregate unpaid principal balance of all Tranche B Loans at such time plus the aggregate amount of LC Obligations outstanding at such time."

        § 2.2.    Committed Loans.    Section 2.1 of the Original Agreement is hereby amended in its entirety to read as follows:

        "Section 2.1    Committed Loans.

        (a)    Tranche A Loans.    Subject to the terms and conditions hereof, Tranche A Lenders severally agree to make loans to Borrower (herein called such Tranche A Lender's "Tranche A Loans") from time to time on any Business Day during the Tranche A Commitment Period so long as (i) all Tranche A Lenders are requested to make Tranche A Committed Loans of the same Type in accordance with their respective Tranche A Percentage Shares and as part of the same Borrowing, (ii) the aggregate amount of all Tranche A Loans outstanding does not exceed the Tranche A Commitment at any time and (iii) the aggregate amount of all Loans (including Committed Loans and Competitive Bid Loans) and all LC Obligations does not exceed the Commitment. The aggregate amount of all Tranche A Loans in any Borrowing must be greater than or equal to $250,000 and must be a higher integral multiple of $100,000 or must equal the unadvanced portion of the Tranche A Commitment. The obligation of Borrower to repay to each Tranche A Lender the aggregate amount of all Tranche A Loans made by such Tranche A Lender, together with interest accruing in connection therewith, shall be evidenced by a single promissory note made by Borrower payable to the order of such Tranche A Lender (herein called such Tranche A Lender's "Tranche A Note") in the form of Exhibit A with appropriate insertions. The amount of principal owing on any Tranche A Lender's Tranche A Note at any given time shall be the aggregate amount of all Tranche A Loans theretofore by such Tranche A Lender made minus all payments of principal theretofore received by such Tranche A Lender on its Tranche A Note. Principal paid or prepaid on the Tranche A Notes may, subject to the terms and conditions hereof, be reborrowed during the Tranche A Commitment Period. Interest on each Tranche A Note shall accrue and be payable as provided herein and therein.

        (b)    Tranche B Loans.    Subject to the terms and conditions hereof, Tranche B Lenders severally agree to make loans to Borrower (herein called such Tranche B Lender's "Tranche B Loans") from time to time on any Business Day during the Tranche B Commitment Period so long as (i) all Tranche B Lenders are requested to make Tranche B Loans of the same Type in accordance with their respective Tranche B Percentage Shares and as part of the same Borrowing, (ii) the sum of (a) the aggregate amount of all Tranche B Loans outstanding plus (b) the LC Obligations outstanding does not exceed the Tranche B Commitment at any time and (iii) the aggregate amount of all Loans (including Committed Loans and Competitive Bid Loans) and all LC Obligations does not exceed the Commitment. The aggregate amount of all Tranche B Loans in any Borrowing must be greater than or equal to $250,000 and must be a higher integral multiple of $100,000 or must equal the unadvanced portion of the Tranche B Commitment. In addition to the foregoing, upon the making of each payment by the Issuing Bank pursuant to any LC, Borrower shall be deemed to have requested each Tranche B Lender to, and such Tranche B Lender shall, make a Tranche B Loan in the amount of such Tranche B Lender's Tranche B Percentage Share of Borrower's consequent reimbursement obligation and apply the proceeds thereof to the payment of such reimbursement obligation. When any Matured LC Obligations is repaid with proceeds of a Borrowing, such Matured LC Obligations so repaid shall be extinguished and such Borrowing shall be governed by the terms of this Agreement applicable to all other Borrowings. Any such Borrowings are Borrowings of Committed Base Rate Loans unless otherwise designated by Borrower in compliance with the notice requirements set forth in Section 2.2. The obligation of Borrower to repay to each Tranche B Lender the aggregate amount of all Tranche B Loans made by such Tranche B Lender, together with interest accruing in connection therewith, shall be evidenced by a single promissory note made by Borrower payable to the order of such Tranche B Lender (herein called such Tranche B Lender's "Tranche B Note") in the form of Exhibit B with appropriate insertions. The amount of principal owing on any Tranche B Lender's Tranche B Note at any given time shall be the aggregate amount of all Tranche B Loans theretofore by such Tranche B Lender made minus all payments of principal theretofore received by such Tranche B Lender on its Tranche B Note. Principal paid or prepaid on the Tranche B Notes may, subject to the terms and conditions hereof, be reborrowed during the Tranche B Commitment Period. Interest on each Tranche B Note shall accrue and be payable as provided herein and therein."

        § 2.3.    Mandatory Prepayments.    Sections 2.7(a) and 2.7(b) of the Original Agreement are hereby amended in their entirety to read as follows:

        "(a)    Tranche A Loans.    If the aggregate unpaid principal balance of the Tranche A Loans ever exceeds the Tranche A Commitment, Borrower shall, immediately after Agent on behalf of Tranche A Majority Lenders gives written notice of such fact to Borrower, make a prepayment to Agent for distribution to Tranche A Lenders in the amount of such excess on the Tranche A Loans in accordance with Tranche A Lenders' Tranche A Percentage Shares.

        (b)    Tranche B Loans.    If the sum of (i) the aggregate unpaid principal balance of the Tranche B Loans and (ii) the LC Obligations outstanding ever exceeds the Tranche B Commitment, Borrower shall, immediately after Agent on behalf of Tranche B Majority Lenders give written notice of such fact to Borrower, make a prepayment to Agent for distribution to Tranche B Lenders in the amount of such excess on the Tranche B Loans in accordance with Tranche B Lenders' Tranche B Percentage Shares and/or, if applicable, deliver LC Collateral as required by Section 3.8."

        § 2.4.    Facility Fees.    Section 2.9 of the Original Agreement is hereby amended in its entirety to read as follows:

        "Section 2.9    Facility Fees.    In consideration of Lenders' commitment to enter into this Agreement and to advance funds to Borrower hereunder, (i) Borrower will pay to Agent, for pro rata distribution to each Tranche A Lender in accordance with its Tranche A Percentage Share, a facility fee for Tranche A Commitment determined on a daily basis by applying the Tranche A Facility Fee Rate to the Tranche A Commitment, and (ii) Borrower will pay to Agent for pro rata distribution to each Tranche B Lender in accordance with its Tranche B Percentage Share, a facility fee for the Tranche B Commitment determined on a daily basis by applying the Tranche B Facility Fee Rate to the Tranche B Commitment. Promptly at the end of each Fiscal Quarter Agent shall calculate the facility fees then due and shall notify Borrower thereof. Borrower shall pay such facility fee to Agent within five Business Days after receiving such notice."

        § 2.5.    LCs.    Article III of the Original Agreement is hereby amended in its entirety to read as follows:

"ARTICLE III

        Section 3.1.    LCs.    From time to time during the Tranche B Commitment Period, Borrower may request Issuing Bank to issue, in reliance on the agreements of Tranche B Lenders set forth in Section 3.2(b), letters of credit (each herein called an "LC") by means of an application in the form of Exhibit C, appropriately completed and with a proposed form of LC attached. Issuing Bank shall have no obligation whatsoever to issue any such requested LC, but any such LC which Issuing Bank does issue shall be subject to all terms and provisions hereof relating to LCs, and shall be subject to the following restrictions: (a) no LC issued hereunder shall have an expiration date later than the earlier of two years after the date of issuance thereof or the end of the Tranche B Commitment Period, without the prior written consent of all Tranche B Lenders; (b) no LC issued hereunder shall be issued in an amount greater than $10,000,000 without the prior written consent of Tranche B Majority Lenders; (c) the LC Obligations outstanding shall at no time exceed the LC Sublimit; (d) the sum of (i) the LC Obligations outstanding and (ii) the aggregate amount of all Tranche B Loans does not exceed the Tranche B Commitment; and (e) the aggregate amount of all Loans (including Committed Loans and Competitive Bid Loans) and all LC Obligations does not exceed the Commitment.

        Section 3.2.    Reimbursement of LCs.

        (a)    Reimbursement by Borrower.    Each payment by Issuing Bank pursuant to any LC (whether in response to a draft, a demand for payment, or otherwise), shall constitute a loan to and an obligation of Borrower. Borrower hereby promises to pay to Issuing Bank, or to Issuing Bank's order, at Issuing Bank's office at 901 Main Street, Dallas, Texas, on demand, any and all amounts paid by Issuing Bank pursuant to any and all LCs (such amounts being herein called the "Matured LC Obligations"). Section 2.1(b) describes certain situations in which such payments may be made with funds advanced by Tranche B Lenders under the Tranche B Notes, but Borrower's obligations to pay the Matured LC Obligations as provided in this section are absolute and not contingent upon the conditions for such Borrowings being met. Borrower hereby promises to pay to Issuing Bank, or to Issuing Bank's order, at Issuing Bank's office at 901 Main Street, Dallas, Texas, on demand, interest at the Default Rate on (a) any outstanding Matured LC Obligations and (b) any fees or other amounts due with respect to LCs (to the extent the same can legally bear interest). Borrower hereby promises to pay, when due, all present and future taxes, levies, costs and charges whatsoever imposed, assessed, levied or collected on, under or in respect of this Agreement or any LC and any payments of principal, interest or other amounts made on or in respect of any thereof (excluding, however, any such taxes, levies, costs and charges imposed on or measured by the overall net income of Issuing Bank). Borrower promises to indemnify Issuing Bank against, and to reimburse Issuing Bank on demand for, any of the foregoing taxes, levies, costs or charges paid by Issuing Bank and any loss, liability, claim or expense, including interest, penalties and legal fees, that Issuing Bank may incur because of or in connection with the failure of Borrower to make any such payment of taxes, levies, costs or charges when due or any payment of Matured LC Obligations when due. In addition, and without limiting the generality of the foregoing, if any law, regulation or the interpretation thereof by any court or administrative or governmental authority shall either impose, modify or deem applicable any capital, reserve, insurance premium or similar requirement against letters of credit issued by Issuing Bank and the result thereof shall be to increase the cost to Issuing Bank of issuing or maintaining any letter of credit; then, on demand by Issuing Bank, Borrower further promises to pay to Issuing Bank, from time to time, additional amounts which shall be sufficient to compensate Issuing Bank for the portion of such increased costs allocable to the LCs. A written advice(s) setting forth in reasonable detail such costs incurred by Issuing Bank, submitted by Issuing Bank to Borrower from time to time, shall be conclusive, absent manifest error, as to the amount thereof.

        (b)    Reimbursement by Tranche B Lenders.    Issuing Bank irrevocably agrees to grant and hereby grants to each Tranche B Lender, and, to induce Issuing Bank to issue LCs hereunder, each Tranche B Lender irrevocably agrees to accept and purchase and hereby accepts and purchases from Issuing Bank, on the terms and conditions hereinafter stated, for such Tranche B Lender's own account and risk an undivided interest equal to such Tranche B Lender's Tranche B Percentage Share of Issuing Bank's obligations and rights under each LC issued hereunder and the amount of each draft paid by Issuing Bank thereunder. In the event that Borrower should fail to pay Issuing Bank on demand the amount of any draft or other request for payment drawn under or purporting to be drawn under a LC as provided in subsection (a) above, each Tranche B Lender shall, before 2:00 p.m. (Dallas Time) on the Business Day Issuing Bank shall have given notice to Tranche B Lenders of Borrower's failure to so pay Issuing Bank, if such notice is given by 10:00 am., Dallas Time (or on the Business Day immediately succeeding the day such notice is given after 10:00 am. Dallas Time), pay to Issuing Bank at Issuing Bank's offices in Dallas, Texas, in legal tender of the United States of America, in same day funds, such Tranche B Lender's Tranche B Percentage Share of the amount of such draft or other request for payment from Borrower plus interest on such amount from the date Issuing Bank shall have paid such draft or request for payment to the date of such payment by such Tranche B Lender at the Default Rate. Each Tranche B Lender's obligation to make payment to Issuing Bank pursuant to the terms of this Section 3.2(b) is irrevocable and unconditional. If any such amount required to be paid by any Tranche B Lender pursuant to this Section 3.2(b) is not in fact made available by such Tranche B Lender to Issuing Bank within three Business Days after the date such payment is due, Issuing Bank shall be entitled to recover from such Tranche B Lender, on demand, such amount with interest thereon calculated from such due date at the Default Rate. A written advice(s) setting forth in reasonable detail the amounts owing under this Section 3.2, submitted by Issuing Bank to Borrower from time to time, shall be conclusive, absent manifest error, as to the amounts thereof. Whenever, at any time after Issuing Bank has made payment under any LC, and has received from any Tranche B Lender its Tranche B Percentage Share of such payment in accordance with this Section 3.2(b), Issuing Bank receives any payment related to such LC (whether directly from Borrower or otherwise, including proceeds of collateral applied thereto by Issuing Bank), or any payment of interest on account thereof, Issuing Bank will distribute to such Tranche B Lender its Tranche B Percentage Share thereof; provided, however, that in the event that any such payment received by Issuing Bank shall be required to be returned by Issuing Bank, such Tranche B Lender shall return to Issuing Bank the portion thereof previously distributed by Issuing Bank to it.

        Section 3.3.    Transferees of LCs.    Borrower agrees that if any LC provides that it is transferable, Issuing Bank is under no duty to determine the proper identity of anyone appearing as transferee of such LC, nor shall Issuing Bank be charged with responsibility of any nature or character for the validity or correctness of any transfer or successive transfers. Payment by Issuing Bank to any purported transferee or transferees as determined by Issuing Bank is hereby authorized and approved, and Borrower further agrees to hold Issuing Bank and each Tranche B Lender harmless and indemnified against any liability or claim in connection with or arising out of the foregoing or the circumstances described in Section 3.6.

        Section 3.4.    Extension of Maturity of LCs.    Borrower agrees that in the event of any extension of the maturity or time for presentation of drafts or demands for payment or any other modification of the terms of any LC at the request of Borrower or by order of any court or tribunal, with or without notification to others, or in the event of any increase in the amount of any LC at the request of Borrower or by order of any court or tribunal, this Agreement shall be binding upon Borrower with respect to the LC so increased or otherwise modified, with respect to drafts and demands for payment thereunder, and with respect to any action taken in accordance with such extension, increase or other modification by Issuing Bank or by any bank which is a confirming bank or an advising bank with respect to any LC.

        Section 3.5.    Restriction on Liability.    Neither Issuing Bank nor any bank which is a confirming bank or an advising bank with respect to an LC (in this section called a "correspondent") shall be responsible for (a) the use which may be made of any LC or for any acts or omissions of the users of any LC; (b) the existence or nonexistence of a default under any instrument secured or supported by any LC or any other event which gives rise to a right to call upon any LC; (c) the validity, sufficiency or genuineness of any document delivered in connection with any LC, even if such documents should in fact prove to be in any or all respects invalid, fraudulent or forged; (d) except as specifically required by an LC, failure of any instrument to bear any reference or adequate reference to any LC, or failure of documents to accompany any draft at negotiation or failure of any person to note the amount of any draft on the reverse of any LC or surrender or take up any LC; or (e) errors, omissions, interruptions or delays in transmission or delivery of any messages by mail, cable, telegraph, wireless or otherwise. Issuing Bank shall not be responsible for any act, error, neglect or default, omission, insolvency or failure in the business of any of the correspondents or any refusal by Issuing Bank or any of the correspondents to pay or honor drafts drawn under any LC because of any applicable law, decree or edict, legal or illegal, of any governmental agency now or hereafter enforced or for any matter beyond the control of Issuing Bank. The happening of any one or more of the contingencies referred to in the preceding clauses of this paragraph shall not affect, impair or prevent the vesting of any of the rights or powers of Issuing Bank and Tranche B Lenders under this Agreement, or the obligation of Borrower to make reimbursement. In furtherance and extension and not in limitation of the specific provisions hereinabove set forth Borrower agrees that any action taken or omitted to be taken by Issuing Bank or any Tranche B Lender or by any correspondent under or in connection with any LC shall be binding on Borrower and shall not put Issuing Bank or any Tranche B Lender or any correspondent under any resulting liability to Borrower unless grossly negligent or in breach of good faith.

        Section 3.6.    No Duty to Inquire.    Borrower agrees that Issuing Bank is authorized and instructed to accept and pay drafts and demands for payment under the LCs without requiring, and without responsibility for, either at the time of acceptance or payment or thereafter, the determination as to the existence of any event giving rise thereto or the proper identity or authority of anyone appearing on behalf of the beneficiary of any LC.

        Section 3.7.    LC Fees.    In consideration of any issuance by Issuing Bank of LCs hereunder and of Tranche B Lender's incurrence of a reimbursement obligation with respect to such LCs, Borrower agrees to pay (a) to Agent for pro rata distribution to each Tranche B Lender in accordance with its Tranche B Percentage Share, a letter of credit fee at a rate equal to the Tranche B Eurodollar Spread then in effect, and (b) to such Issuing Bank for its own account, a letter of credit fronting fee at a rate equal to one-eighth of one percent per annum in each case times the actual daily maximum amount available to be drawn under each Letter of Credit. Such fee for each Letter of Credit shall be due and payable on the last Business Day of each Fiscal Quarter, commencing with the first such date to occur after the issuance of such letter of Credit, and on the expiration date for such Letter of Credit. Any change in the letter of credit fee rate as a result of a change in the Debt to Capitalization Ratio or Senior Debt to Capitalization Ratio shall become effective on the fifth Business Day following the date on which a notice is given to Agent pursuant to Section 2.17 or Lenders otherwise become aware of such a change in the Debt to Capitalization Ratio or the Senior Debt to Capitalization Ratio.

        Section 3.8.    LC Collateral.

        (a)    Cash Collateralize.    Upon the request of Agent, (i) if LC Issuer has honored any full or partial drawing request under any Letter of Credit and such drawing has resulted in an extension of credit resulting from such drawing which has not been reimbursed on the date when made or refinanced as a Borrowing, or (ii) if, as of the seventh day prior to the Tranche B Maturity Date, any Letter of Credit remains outstanding and partially or wholly undrawn, the Borrower shall immediately pay to LC Issuer an amount equal to the LC Obligations then outstanding with respect to such Letter of Credit. LC Issuer will hold such amount as security for the remaining LC Obligations (all such amounts held as security for LC Obligations being herein collectively called "LC Collateral") and the other Obligations, and such collateral may be applied from time to time to any Matured LC Obligations or other Obligations which are due and payable. Neither this subsection nor the following subsection shall, however, limit or impair any rights which LC Issuer may have under any other document or agreement relating to any LC, LC Collateral or LC Obligation, including any LC Application, or any rights which any Lender Party may have to otherwise apply any payments by Borrower and any LC Collateral hereunder.

        (b)    Acceleration of LC Obligations.    If the Obligations or any part thereof become immediately due and payable pursuant to Section 8.1 then, unless Tranche B Majority Lenders otherwise specifically elect to the contrary (which election may thereafter be retracted by Tranche B Majority Lenders at any time), all LC Obligations shall become immediately due and payable without regard to whether or not actual drawings or payments on the LC's have occurred, and Borrower shall be obligated to pay to LC Issuer immediately an amount equal to the aggregate LC Obligations which are then outstanding.

        (c)    Investment of LC Collateral.    Pending application thereof, all LC Collateral shall be invested by LC Issuer in such investments as LC Issuer may choose in its sole discretion. All interest on (and other proceeds of) such investments shall be reinvested or applied to Matured LC Obligations or other Obligations which are due and payable. When all Obligations have been satisfied in full, including all LC Obligations, all LC's have expired or been terminated, and all of Borrower's reimbursement obligations in connection therewith have been satisfied in full, LC Issuer shall release any remaining LC Collateral. Borrower hereby assigns and grants to LC Issuer a continuing security interest in all LC Collateral paid by it to LC Issuer, all investments purchased with such LC Collateral, and all proceeds thereof to secure its Matured LC Obligations and its Obligations under this Agreement, each Note, and the other Loan Documents, and Borrower agrees that such LC Collateral, investments and proceeds shall be subject to all of the terms and conditions of the Security Documents. Borrower further agrees that LC Issuer shall have all of the rights and remedies of a secured party under the Uniform Commercial Code as adopted in the State of Texas with respect to such security interest and that an Event of Default under this Agreement shall constitute a default for purposes of such security interest.

        (d)    Payment of LC Collateral.    When Borrower is required to provide LC Collateral for any reason and fails to do so on the day when required, LC Issuer may without notice to Borrower or any other Related Person provide such LC Collateral (whether by application of proceeds of other Collateral, by transfers from other accounts maintained with LC Issuer, or otherwise) using any available funds of Borrower or any other Person also liable to make such payments. Any such amounts which are required to be provided as LC Collateral and which are not provided on the date required shall, for purposes of each Security Document, be considered past due Obligations owing hereunder, and LC Issuer is hereby authorized to exercise its respective rights under each Security Document to obtain such amounts."

        § 2.6.    Reliance by Agent.    The third sentence of Section 9.2 of the Original Agreement is hereby amended in its entirety to read as follows:

"As to any matters not expressly provided for by this Agreement, Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Tranche A Majority Lenders, Tranche B Majority Lenders or Majority Lenders, as provided in this Agreement, and such instructions shall be binding on all of Tranche A Lenders, Tranche B Lenders or Lenders, respectively; provided, however, that Agent shall not be required to take any action that exposes Agent to personal liability or that is contrary to any Loan Document or applicable law or unless it shall first be indemnified to its satisfaction by Lenders against any and all liability and expense which may be incurred by it by reason of taking any such action."

        § 2.7.    Waivers and Amendments.    Section 10.1(b) of the Original Agreement is hereby amended in its entirety to read as follows:

        "(b) No waiver or supplement to this Agreement or the other Loan Documents shall be valid or effective against any party hereto unless the same is in writing and signed by (i) if such party is Borrower, by Borrower, (ii) if such party is Agent, by Agent, (iii) if such party is Issuing Bank, by Issuing Bank, (iv) in any provision requiring the consent of Tranche A Majority Lenders, if such party is a Tranche A Lender, by such Tranche A Lender or by Agent on behalf of Tranche A Lenders with the written consent of Tranche A Majority Lenders, (v) in any provision requiring the consent of Tranche B Majority Lenders, if such party is a Tranche B Lender, by such Tranche B Lender or by Agent on behalf of Tranche B Lenders with the written consent of Tranche B Majority Lenders, and (vi) in any provision requiring the consent of Majority Lenders, if such party is a Lender, by Majority Lenders or by Agent on behalf of Lenders with the written consent of Majority Lenders (which consent has already been given as to the termination of the Loan Documents as provided in Section 10.8). Notwithstanding the foregoing or anything to the contrary herein, no such amendment or waiver shall, unless signed by all Lenders or by Agent on behalf of all Lenders with the prior consent of each individual Lender, (1) waive any of the conditions specified in Article IV (provided that Agent may in its discretion withdraw any request it has made under Section 4.2(f)), (2) increase the Percentage Share, the Tranche A Percentage Share, the Tranche B Percentage Share or Commitment of such Lender or subject such Lender to any additional obligations, (3) reduce any fees hereunder, or the principal of, or interest on, such Lender's Note, (4) postpone any date fixed for any payment of any fees hereunder, or principal of, or interest on, such Lender's Note, (5) amend the definition herein of "Majority Lenders" or otherwise change the aggregate amount of Percentage Shares which is required for Agent, Lenders or any of them to take any particular action under the Loan Documents, (6) release Borrower from its obligation to pay such Lender's Note or any Guarantor from its guaranty of such payment, or (7) release any Collateral except in accordance with the express terms of any Loan Document. Notwithstanding the foregoing or anything to the contrary herein, Agent shall not, (a) without the prior consent of each individual Tranche A Lender, execute and deliver on behalf of such Tranche A Lender any waiver or amendment which would amend the definition herein of "Tranche A Majority Lenders" and (b) without the prior consent of each individual Tranche B Lender, execute and deliver on behalf of such Tranche B Lender any waiver or amendment which would amend the definition herein of "Tranche B Majority Lenders."

        § 2.8.    Limitation on Sales of Property.    The following clause (C) is hereby added to subsection (iii) of Section 6.2(d) of the Original Agreement:

        "(C)   the Toca gas processing and liquid fractionation facility located in Saint Bernard Parish Louisiana; and"

        § 2.9.    Assignments and Participations.    Section 10.5 of the Original Agreement is hereby amended in its entirety to read as follows:

        "(a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby and, to the extent expressly contemplated hereby, any indemnified party) any legal or equitable right, remedy or claim under or by reason of this Agreement.

        (b)  Any Lender may assign to one or more Eligible Assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans (including for purposes of this subsection (b), participations in LC Obligations) at the time owing to it); provided that (i) except in the case of an assignment of the entire remaining amount of the assigning Lender's Commitment and the Loans at the time owing to it or in the case of an assignment to a Lender or an Affiliate of a Lender or an Approved Fund with respect to a Lender, the aggregate amount of the Commitment (which for this purpose includes Loans outstanding thereunder) subject to each such assignment, determined as of the date the Assignment and Acceptance with respect to such assignment is delivered to the Agent, shall not be less than $5,000,000, unless each of the Agent and, so long as no Event of Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed), (ii) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender's rights and obligations under this Agreement with respect to the Loans or the Commitment assigned, except that this clause (ii) shall not prohibit any Lender from assigning all or a portion of its rights and obligations among separate Tranches on a non-pro rata basis, and (iii) the parties to each assignment shall execute and deliver to the Agent an Assignment and Acceptance, together with a processing and recordation fee of $3,500. Subject to acceptance and recording thereof by the Agent pursuant to subsection (c) of this Section, from and after the effective date specified in each Assignment and Acceptance, the Eligible Assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all of the assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 9.11). The Borrower (at its expense) shall execute and deliver new or replacement Notes to the assigning Lender and the assignee Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this subsection shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.

        (c)  The Agent, acting solely for this purpose as an agent of the Borrower, shall maintain at the Agent's office (which must be in the United States of America) a copy of each Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amount of the Loans and LC Obligations owing to, each Lender pursuant to the terms hereof from time to time (the "Register"). The entries in the Register shall be conclusive, and the Borrower, the Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

        (d)  Any Lender may, without the consent of, or notice to, the Borrower or theAgent, sell participations to one or more banks or other entities (a "Participant") in all or a portion of such Lender's rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Loans (including such Lender's participations in LC Obligations) owing to it); provided that (i) such Lender's obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) the Borrower, the Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, waiver or other modification that would (i) postpone any date upon which any payment of money is scheduled to be paid to such Participant, (ii) reduce the principal, interest, fees or other amounts payable to such Participant,or (iii) release any Guarantor from its guaranty. Subject to subsection (e) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.10, 2.15, and 2.16 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 7.2 as though it were a Lender.

        (e)  A Participant shall not be entitled to receive any greater payment under Section 2.10 or 2.15 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower's prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.15 unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 10.14 as though it were a Lender.

        (f)    Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement (including under its Notes, if any) to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank; provided that no such pledge or assignment shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

        (g)  If the consent of the Borrower to an assignment or to an Eligible Assignee is required hereunder (including a consent to an assignment which does not meet the minimum assignment threshold specified in clause (i) of the proviso to the first sentence of Section 10.5(b)), the Borrower shall be deemed to have given its consent five Business Days after the date notice thereof has been delivered by the assigning Lender (through the Agent) unless such consent is expressly refused by the Borrower prior to such fifth Business Day.

        (h)  As used herein, the following terms have the following meanings:

"Fund" means any Person (other than a natural Person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

"Approved Fund" means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

        (i)    Notwithstanding anything to the contrary contained herein, if at any time Bank of America assigns its entire Percentage Share of the Commitment and Loans pursuant to subsection (b) above, Bank of America may, (i) upon 30 days' notice to the Borrower and the Lenders, resign as LC Issuer. In the event of any such resignation as LC Issuer, the Borrower shall be entitled to appoint from among the Lenders a successor LC Issuer hereunder; provided, however, that no failure by the Borrower to appoint any such successor shall affect the resignation of Bank of America as LC Issuer. Bank of America shall retain all the rights and obligations of the LC Issuer hereunder with respect to all LC's outstanding as of the effective date of its resignation as LC Issuer and all LC Obligations with respect thereto."

        § 2.10.    Foreign Lenders.    Section 10.14 is hereby added to the Original Agreement to read as follows:

"Section 10.14. Each Lender that is a "foreign corporation, partnership or trust" within the meaning of the Internal Revenue Code of 1986 (a "Foreign Lender") shall deliver to the Agent, prior to receipt of any payment subject to withholding under the Internal Revenue Code of 1986 (or after accepting an assignment of an interest herein), two duly signed completed copies of either IRS Form W-8BEN or any successor thereto (relating to such Person and entitling it to an exemption from, or reduction of, withholding tax on all payments to be made to such Person by the Borrower pursuant to this Agreement) or IRS Form W-8ECI or any successor thereto (relating to all payments to be made to such Person by the Borrower pursuant to this Agreement) or such other evidence satisfactory to the Borrower and the Agent that such Person is entitled to an exemption from, or reduction of, U.S. withholding tax. Thereafter and from time to time, each such Person shall (a) promptly submit to the Agent such additional duly completed and signed copies of one of such forms (or such successor forms as shall be adopted from time to time by the relevant United States taxing authorities) as may then be available under then current United States laws and regulations to avoid, or such evidence as is satisfactory to the Borrower and the Agent of any available exemption from or reduction of, United States withholding taxes in respect of all payments to be made to such Person by the Borrower pursuant to this Agreement, (b) promptly notify the Agent of any change in circumstances which would modify or render invalid any claimed exemption or reduction, and (c) take such steps as shall not be materially disadvantageous to it, in the reasonable judgment of such Lender, and as may be reasonably necessary (including the re-designation of its Lending Office) to avoid any requirement of applicable Laws that the Borrower make any deduction or withholding for taxes from amounts payable to such Person. If such Person fails to deliver the above forms or other documentation, then the Agent may withhold from any interest payment to such Person an amount equivalent to the applicable withholding tax imposed by Sections 1441 and 1442 of the Internal Revenue Code of 1986, without reduction. If any governmental authority asserts that the Agent did not properly withhold any tax or other amount from payments made in respect of such Person, such Person shall indemnify the Agent therefor, including all penalties and interest, any taxes imposed by any jurisdiction on the amounts payable to the Agent under this Section, and costs and expenses (including Attorney Costs) of the Agent. The obligation of the Lenders under this Section shall survive the payment of all Obligations and the resignation or replacement of the Agent."

        § 2.11.    Lenders Schedule and Assignment and Acceptance.    Schedule 3 attached to the Original Agreement is deleted and Schedule 3 hereto is substituted therefor. Exhibit G attached to the Original Agreement is deleted and Exhibit G hereto is substituted therefor.

ARTICLE IIA.
Amendment to Intercreditor Agreement

        § 2.1A.    Amendment to Intercreditor Agreement.    Each of Agent, Prudential, as successor in interest to PICA and each Lender hereby agrees that the term "Prudential Affiliate" in the Original Intercreditor Agreement is hereby amended in its entirety to mean the following:

"Prudential Affiliate" shall mean any corporation or other entity controlling, controlled by, or under common control with, Prudential Investment Management, Inc. ("Prudential") either directly or through subsidiaries and (ii) any managed account or investment fund which is managed by Prudential or a Prudential Affiliate described in clause (i) of this definition.

Agent, Prudential and Lenders hereby further agree that, for purposes of the definition of "Prudential Affiliate" the terms "control", "controlling" and "controlled" shall mean the ownership, directly or through subsidiaries, of a majority of a corporation's or other entity's voting stock or equivalent voting securities or interests.

ARTICLE IIB.
Consent to Restated Master Shelf Agreement

        § 2.1B.    Consent of Majority Lenders.    Majority Lenders hereby consent to Borrower's execution of the Restated Prudential Agreement and the provisions contained therein, including without limitation, the extension of the period during which senior notes may be issued thereunder and the increase of the facility size by $65,000,000 (allowing Borrower to issue an additional $65,000,000 in Debt Securities).

ARTICLE III.
Conditions of Effectiveness

        § 3.1.    Effective Date.

        (a)  Article II of this Amendment shall become effective as of July 30, 2002 when, and only when:

        (i)    Agent shall have received this Amendment, duly authorized, executed and delivered by Borrower, Agent, and Lenders in form and substance satisfactory to Agent;

        (ii)  Agent shall have received a certificate of a duly authorized officer of Borrower dated the date of this Amendment certifying: (i) that all of the representations and warranties set forth in Article IV hereof are true and correct at and as of the time of such effectiveness; and(ii) as to such other corporate matters as Agent shall deem necessary;

        (iii)  Agent shall have received an opinion of General Counsel to Borrower with respect to this Amendment, in form and substance acceptable to Agent;

        (iv)  All fees and disbursements of Thompson & Knight L.L.P. relating to this Amendment and the Loan Agreement as provided in the Loan Agreement have been fully paid; and

        (v)  Agent shall have additionally received such other documents as Agent may reasonably request.

        (b)  Article IIA of this Amendment shall become effective as of the date first written above when and only when Agent shall have received this Amendment, duly authorized, executed and delivered by Agent, each Lender and Prudential.

        (c)  The remainder of this Amendment shall become effective as of the date first written above when and only when:

        (i)    Agent shall have received this Amendment, duly authorized, executed and delivered by Borrower, Agent, and Majority Lenders in form and substance satisfactory to Agent; and

        (ii)  All of the conditions listed in subsections (a)(ii) through (a)(v) of this Section 3.1 have been satisfied.

ARTICLE IV.
Representations and Warranties

        § 4.1.    Representations and Warranties of Borrower.    In order to induce each Lender to enter into this Amendment, Borrower represents and warrants on the date hereof and as of the Effective Date to each Lender that:

        (a)  The representations and warranties contained in Article V of the Original Agreement are true and correct at and as of the time of the effectiveness hereof (except as such representations and warranties have been modified by the transactions contemplated herein).

        (b)  Borrower is duly authorized to execute and deliver this Amendment and Borrower is and will continue to be duly authorized to borrow monies and to perform its obligations under the Loan Agreement. Borrower has duly taken all corporate action necessary to authorize the execution and delivery of this Amendment.

        (c)  The execution and delivery by Borrower of this Amendment, the performance of its obligations hereunder and the consummation of the transactions contemplated hereby do not and will not conflict with any provision of law, statute, rule or regulation or of the certificate of incorporation and bylaws of Borrower or of any material agreement, judgment, license, order or permit applicable to or binding upon Borrower or result in the creation of any lien, charge or encumbrance upon any assets or properties of Borrower. Except for those which have been obtained, no consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by Borrower of this Amendment.

        (d)  When duly executed and delivered, this Amendment, the Loan Agreement, and each other Loan Document, as affected hereby, will be a legal and binding obligation of each Related Person that is a party hereto and thereto enforceable against such Related Person in accordance with its terms, except as limited by bankruptcy, insolvency or similar laws of general application relating to the enforcement of creditors' rights and by equitable principles of general application.

        (e)  The audited Consolidated financial statements of Borrower dated as of December 31, 2001, and the unaudited Consolidated financial statements of Borrower dated as of September 30, 2002, fairly present the Consolidated financial position at such date of Borrower and the Consolidated statement of operations and the changes in Consolidated financial position for the periods ending on such date for Borrower. Copies of such financial statements have heretofore been delivered to Agent. Since December 31, 2001, no material adverse change has occurred in the financial condition or business or in the Consolidated financial condition or business of Borrower.

ARTICLE V.
Miscellaneous

        § 5.1.    Ratification of Agreements.    The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. Any reference to the Loan Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. The Loan Documents, as they may be amended or affected by this Amendment, are hereby ratified and confirmed in all respects. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders under the Loan Agreement, the Notes, or any other Loan Document nor constitute a waiver of any provision of the Loan Agreement, the Notes, or any other Loan Document.

        § 5.2.    Survival of Agreements.    All representations, warranties, covenants and agreements of Borrower herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of the Loans, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by Borrower hereunder or under the Loan Agreement to any Lender shall be deemed to constitute representations and warranties by, and/or agreements and covenants of, Borrower under this Amendment and under the Loan Agreement.

        § 5.3.    Loan Documents.    This Amendment is a Loan Document, and all provisions in the Loan Agreement pertaining to Loan Documents apply hereto.

        § 5.4.    Governing Law.    This Amendment shall be governed by and construed in accordance the laws of the State of Texas and any applicable laws of the United States of America in all respects, including construction, validity and performance.

        § 5.5.    Counterparts.    This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be duly executed by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK.]

        IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

WESTERN GAS RESOURCES, INC.
By:	Name: Title:
BANK OF AMERICA, N.A., as Agent and Lender
By:	Name: Title:
ABN AMRO BANK N.V., a Lender
By:	Name: Title:
By:	Name: Title:
BANK ONE, NA (MAIN OFFICE—CHICAGO), a Lender
By:	Name: Title:
COMERICA BANK—TEXAS, a Lender
By:	Name: Title:
CREDIT LYONNAIS NEW YORK BRANCH, a Lender
By:	Name: Title:

FLEET NATIONAL BANK, a Lender
By:	Name: Title:
SOCIÉTÉ GÉNÉRALE SOUTHWEST AGENCY, a Lender
By:	Name: Title:
UNION BANK OF CALIFORNIA, N.A., a Lender
By:	Name: Title:
U.S. BANK NATIONAL ASSOCIATION, a Lender
By:	Name: Title:
WELLS FARGO BANK, N.A., a Lender
By:	Name: Title:

        The undersigned is executing this Tenth Amendment to Loan Agreement and Amendment to Intercreditor Agreement for the sole purpose of agreeing to Section 2.1A, Amendment to Intercreditor Agreement, and for no other purpose.

PRUDENTIAL INVESTMENT MANAGEMENT, INC., for itself and on behalf of the holders of the Notes
By:	Name: Title:

CONSENT AND AGREEMENT

        Each of the undersigned hereby (i) consents to the provisions of this Amendment and the transactions contemplated herein, and (ii) ratifies and confirms its respective Guaranty dated as of April 29, 1999 made by it in favor of Agent for the benefit of each Lender, and agrees that its obligations and covenants thereunder are unimpaired hereby and shall remain in full force and effect. This Consent and Agreement is effective as of July 30, 2002.

Date:                        , 2003

MIGC, INC.
WESTERN GAS RESOURCES TEXAS, INC.
MOUNTAIN GAS RESOURCES, INC.
LANCE OIL & GAS COMPANY, INC.
WESTERN GAS WYOMING, L.L.C.
By:	Name: Title:

CONSENT AND AGREEMENT

        The undersigned hereby (i) consents to the provisions of this Amendment and the transactions contemplated herein, and (ii) ratifies and confirms its Guaranty dated as of October 14, 1999 made by it in favor of Agent for the benefit of each Lender, and agrees that its obligations and covenants thereunder are unimpaired hereby and shall remain in full force and effect. This Consent and Agreement is effective as of July 30, 2002.

Date:                        , 2003

MGTC, INC.
By:	Name: Title:

EXHIBIT G

FORM OF ASSIGNMENT AND ACCEPTANCE

        Reference is made to that certain Loan Agreement, dated as of April 29, 1999 (as amended, restated, extended, supplemented or otherwise modified in writing from time to time, the "Agreement;" the terms defined therein being used herein as therein defined), among Western Gas Resources, Inc., a Delaware corporation (the ''Borrower"), the Lenders from time to time party thereto, and Bank of America, N.A., as Agent and Issuing Bank.

        The assignor identified on the signature page hereto (the "Assignor") and the assignee identified on the signature page hereto (the "Assignee") agree as follows:

        1.    (a) Subject to paragraph 11, effective as of the date specified on Schedule 1 hereto (the "Effective Date"), the Assignor hereby irrevocably sells and assigns to the Assignee without recourse to the Assignor, and the Assignee hereby irrevocably purchases and assumes from the Assignor without recourse to the Assignor, the interest described on Schedule 1 hereto (the "Assigned Interest") in and to the Assignor's rights and obligations under the Agreement.

        (b)  From and after the Effective Date, (i) the Assignee shall be a party under the Agreement and will have all the rights and obligations of a Lender for all purposes under the Loan Documents to the extent of the Assigned Interest and be bound by the provisions thereof, and (ii) the Assignor shall relinquish its rights and be released from its obligations under the Agreement to the extent of the Assigned Interest. The Assignor and/or the Assignee, as agreed by the Assignor and the Assignee, shall deliver, in immediately available funds, any applicable assignment fee required under Section 10.5 of the Agreement.

        2.    On the Effective Date, the Assignee shall pay to the Assignor, in immediately available funds, an amount equal to the purchase price of the Assigned Interest as agreed upon by the Assignor and the Assignee.

        3.    From and after the Effective Date, the Agent shall make all payments under the Agreement and the Notes, if any, in respect of the Assigned Interest (including all payments of principal, interest and fees with respect thereto) to the Assignee. The Assignor and the Assignee shall make all appropriate adjustments in payments under the Agreement and such Notes, if any, for periods prior to the Effective Date directly between themselves.

        4.    The Assignor represents and warrants to the Assignee that:

        (a)  The Assignor is the legal and beneficial owner of the Assigned Interest, and the Assigned Interest is free and clear of any adverse claim;

        (b)  the Assigned Interest listed on Schedule 1 accurately and completely sets forth the outstanding amount of all Loans and LC Obligations relating to the Assigned Interest as of the Effective Date;

        (c)  it has the power and authority and the legal right to make, deliver and perform, and has taken all necessary action, to authorize the execution, delivery and performance of this Assignment and Acceptance, and any and all other documents delivered by it in connection herewith and to fulfill its obligations under, and to consummate the transactions contemplated by, this Assignment and Acceptance and the Loan Documents, and no consent or authorization of, filing with, or other act by or in respect of any governmental authority, is required in connection in connection herewith or therewith; and

        (d)  this Assignment and Acceptance constitutes the legal, valid and binding obligation of the Assignor.

        The Assignor makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or any of its Affiliates or the performance by the Borrower or any of its Affiliates of their respective obligations under the Loan Documents, and assumes no responsibility with respect to any statements, warranties or representations made under or in connection with any Loan Document or the execution, legality, validity, enforceability, genuineness, sufficiency or value of any Loan Document other than as expressly set forth above.

        5.    The Assignee represents and warrants to the Assignor and the Agent that:

        (a)  it is an Eligible Assignee;

        (b)  it has the full power and authority and the legal right to make, deliver and perform, and has taken all necessary action, to authorize the execution, delivery and performance of this Assignment and Acceptance, and any and all other documents delivered by it in connection herewith and to fulfill its obligations under, and to consummate the transactions contemplated by, this Assignment and Acceptance and the Loan Documents, and no consent or authorization of, filing with, or other act by or in respect of any governmental authority, is required in connection in connection herewith or therewith;

        (c)  this Assignment and Acceptance constitutes the legal, valid and binding obligation of the Assignee;

        (d)  under applicable laws no tax will be required to be withheld by the Agent or the Borrower with respect to any payments to be made to the Assignee hereunder or under any Loan Document, and unless otherwise indicated in the space opposite the Assignee's signature below, no tax forms described in Section 2.14(d) of the Agreement are required to be delivered by the Assignee; and

        (e)  the Assignee has received a copy of the Agreement, together with copies of the most recent financial statements of the Borrower delivered pursuant thereto, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Acceptance. The Assignee has independently and without reliance upon the Assignor or the Agent and based on such information as the Assignee has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Acceptance. The Assignee will, independently and without reliance upon the Agent or any Lender, and based upon such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Agreement.

        6.    The Assignee appoints and authorizes the Agent to take such action as agent on its behalf and to exercise such powers and discretion under the Agreement, the other Loan Documents or any other instrument or document furnished pursuant hereto or thereto as are delegated to the Agent by the terms thereof, together with such powers as are incidental thereto.

        7.    If either the Assignee or the Assignor desires a Note to evidence its Loans, it shall request the Agent to procure a Note from the Borrower.

        8.    The Assignor and the Assignee agree to execute and deliver such other instruments, and take such other action, as either party may reasonably request in connection with the transactions contemplated by this Assignment and Acceptance.

        9.    This Assignment and Acceptance shall be binding upon and inure to the benefit of the parties and their respective successors and assigns; provided, however, that the Assignee shall not assign its rights or obligations hereunder without the prior written consent of the Assignor and any purported assignment, absent such consent, shall be void.

        10.  This Assignment and Acceptance may be executed by facsimile signatures with the same force and effect as if manually signed and may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. This Assignment and Acceptance shall be governed by and construed in accordance with the laws of the state specified in the Section of the Agreement entitled "Governing Law."

        11.  The effectiveness of the assignment described herein is subject to:

        (a)  if such consent is required by the Agreement, receipt by the Assignor and the Assignee of the consent of the Agent, the Issuing Bank and/or the Borrower to the assignment described herein. By delivering a duly executed and delivered copy of this Assignment and Acceptance to the Agent, the Assignor and the Assignee hereby request any such required consent and request that the Agent register the Assignee as a Lender under the Agreement effective as of the Effective Date; and

        (b)  receipt by the Agent of (or other arrangements acceptable to the Agent with respect to) any applicable assignment fee referred to in Section 10.5 of the Agreement and any tax forms required by Section 2.14(d) of the Agreement.

        By signing below, the Agent agrees to register the Assignee as a Lender under the Agreement, effective as of the Effective Date with respect to the Assigned Interest, and will adjust the registered Percentage Share of the Assignor under the Agreement to reflect the assignment of the Assigned Interest.

        12.  Attached hereto as Schedule 2 is all contact, address, account and other administrative information relating to the Assignee.

IN WITNESS WHEREOF, the parties hereto have caused this Assignment and Acceptance to be executed as of the date first above written by their respective duly authorized officers.

	Assignor:
	[Name of Assignor]
	By:
	Name:
	Title:
Tax forms required by Section 2.14(d) of the Agreement included	Assignee: [Name of Assignee]
	By:
	Name:
	Title:
(Signatures continue)

In accordance with and subject to Section 10.05 of the Loan Agreement, the undersigned consent to the foregoing assignment as of the Effective Date:

WESTERN GAS RESOURCES, INC.

By:

Name:

Title:

BANK OF AMERICA, N.A., as Agent and LC Issuer

By:

Name:

Title:

SCHEDULE 1
TO
ASSIGNMENT AND ACCEPTANCE

THE ASSIGNED INTEREST

Effective Date:

Assigned Commitment	Type and amount of outstanding Obligations assigned	Assigned Tranche A Percentage Share/Tranche B Percentage Share
$	[type]$	%

SCHEDULE 2
TO
ASSIGNMENT AND ACCEPTANCE

ADMINISTRATIVE DETAILS

(Assignee to list names of credit contacts, addresses, phone and facsimile numbers, electronic mail addresses and account and payment information)

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Exhibit 10.28

EX-10.29

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Exhibit 10.29

WESTERN GAS RESOURCES, INC.

SENIOR NOTES

THIRD AMENDED AND RESTATED MASTER SHELF AGREEMENT

Dated as of December 19, 1991
(Effective as of January 13, 2003)

TABLE OF CONTENTS
(Not Part of Agreement)

PARAGRAPH 1. RESTATEMENT AND AMENDMENT; AUTHORIZATION OF ISSUE OF NOTES			1
1A.	Restatement and Amendment of Existing Agreement		1
1B.	Authorization of Issue of Notes		2
PARAGRAPH 2. PURCHASE AND SALE OF NOTES			2
2A.	Facility		2
2B.	Issuance Period		2
2C.	Spread Information		2
2D.	Request for Purchase		3
2E.	Rate Quotes		3
2F.	Acceptance		3
2G.	Market Disruption		3
2H.	Closing		4
	2H(1).	Series H Closing	4
	2H(2).	Subsequent Closings	4
	2H(3).	Rescheduled Closings	4
2I.	Fees		5
	2I(1).	Facility Fee	5
	2I(2).	Delayed Delivery Fee	5
	2I(3).	Cancellation Fee	5
	2I(4).	Structuring Fee	5
PARAGRAPH 3. CONDITIONS PRECEDENT			6
3A.	Conditions of Closing		6
	3A(1).	Certain Documents	6
	3A(2).	Representations and Warranties; No Default	7
	3A(3).	Purchase Permitted by Applicable Laws	7
	3A(4).	Legal Matters	7
	3A(5).	Proceedings	7
	3A(6).	Amendment of Credit Agreements	7
	3A(7).	Facility Fee Payment	7
	3A(8).	Consent of Banks	7
3B.	Conditions to Effectiveness		8
PARAGRAPH 4. PREPAYMENTS			8
4A.	Required Prepayments		8
4B.	Optional Prepayment With Yield-Maintenance Amount		8
	4B(1).	Optional Prepayment At Any Time	8
	4B(2).	Special One Time Option to Prepay Series H Notes	8
4C.	Notice of Optional Prepayment		8
4D.	Application of Prepayments		9
4E.	Retirement of Notes		9

PARAGRAPH 5. AFFIRMATIVE COVENANTS			9
5A.	Financial Statements		9
5B.	Inspection of Property		11
5C.	Covenant to Secure Notes Equally		11
5D.	Agreement Assuming Liability on Notes		11
5E.	Notice of Material Events		11
5F.	Maintenance of Properties		12
5G.	Maintenance of Existence and Qualifications		12
5H.	Insurance		12
5I.	Compliance with Agreements and Law		12
5J.	Compliance with Environmental Laws		12
5K.	Information Required by Rule 144A		13
5L.	ERISA		13
5M.	Guaranties		13
5N.	Pledge of Subsidiary Stock		13
5O.	Credit Fee		14
PARAGRAPH 6. NEGATIVE COVENANTS			14
6A.	Financial Covenants		14
	6A(1).	Consolidated Tangible Net Worth	14
	6A(2).	Total Debt Maintenance	14
	6A(3).	Senior Debt Maintenance	14
	6A(4).	Total Fixed Charge Coverage Ratio	14
	6A(5).	Consolidated Senior Debt to EBITDA	15
6B.	Dividend Limitation		15
6C.	Lien, Debt, and Other Restrictions		15
	6C(1).	Liens	15
	6C(2).	Debt	16
	6C(3).	Limitation on Investments and New Businesses	16
	6C(4).	Sale of Stock and Debt of Subsidiaries	16
	6C(5).	Merger and Sale of Assets	17
	6C(6).	Lease Rentals	18
	6C(7).	Limitation on Credit Extensions	18
	6C(8).	Contracts; Take-or-Pay Agreements	18
	6C(9).	Sale or Discount of Receivables	18
	6C(10).	Guaranties	18
	6C(11).	Transactions With Affiliates	19
	6C(12).	Certain Matters Relating to Subordinated Debt	19
6D.	Issuance of Stock by Subsidiaries		19
6E.	Other Agreements		20
	6E(1).	Modifications	20
	6E(2).	Conflicting Provisions	20
6F.	Restrictions on Hedging Transactions		20
PARAGRAPH 7. EVENTS OF DEFAULT			21
7A.	Acceleration		21
7B.	Rescission of Acceleration		23
7C.	Notice of Acceleration or Rescission		23
7D.	Other Remedies		23

PARAGRAPH 8. REPRESENTATIONS, COVENANTS AND WARRANTIES			24
8A.	Organization		24
8B.	Financial Statements		24
8C.	Actions Pending		24
8D.	Outstanding Debt		25
8E.	Environmental Compliance		25
8F.	Taxes		25
8G.	Conflicting Agreements and Other Matters		25
8H.	Offering of Notes		25
8I.	Regulation U, etc.		25
8J.	ERISA		26
8K.	Governmental Consent		26
8L.	Title to Properties		26
8M.	Hostile Tender Offers		26
8N.	Disclosure		27
8O.	Delivery of NCNB Agreement		27
8P.	Public Utility Holding Company Act; Federal Power Act		27
8Q.	Existing Guaranties		27
8R.	No Default		27
PARAGRAPH 9. REPRESENTATIONS AND COVENANTS OF THE PURCHASERS			27
9A.	Nature of Purchase		27
9B.	Source of Funds		27
9C.	Covenants		28
	9C(1).	Collateral Agent	28
	9C(2).	Pledge Agreements	29
	9C(3).	Intercreditor Agreement	29
PARAGRAPH 10. DEFINITIONS			29
10A.	Yield-Maintenance Terms		29
10B.	Other Terms		30
10C.	Accounting Terms and Determinations		37
PARAGRAPH 11. MISCELLANEOUS			38
11A.	Note Payments		38
11B.	Expenses		38
11C.	Consent to Amendments		38
11D.	Form, Registration, Transfer and Exchange of Notes; Lost Notes		39
11E.	Persons Deemed Owners; Participations		39
11F.	Survival of Representations and Warranties; Entire Agreement		40
11G.	Successors and Assigns		40
11H.	Disclosure to Other Persons; Confidentiality		40
11I.	Notices		40
11J.	Payments Due on Non-Business Days		41
11K.	Satisfaction Requirement		41
11L.	Governing Law		41
11M.	Severability		41
11N.	Descriptive Headings		41
11O.	Counterparts		41
11P.	Binding Agreement		41
11Q.	Agreement Regarding Paragraph 6A(3)		41

PURCHASER SCHEDULE

SCHEDULE 5A—FORM OF PROJECTIONS
SCHEDULE 6C(2)—EXISTING DEBT AND LIENS
SCHEDULE 6C(3)—JOINT VENTURES
SCHEDULE 6C(8)—COUNTERPARTIES
EXHIBIT A-1—FORM OF NOTE
EXHIBIT A-2—FORM OF SERIES H NOTE
EXHIBIT B—FORM OF REQUEST FOR PURCHASE
EXHIBIT C—FORM OF CONFIRMATION OF ACCEPTANCE
EXHIBIT D—FORM OF OPINION OF COMPANY'S COUNSEL
EXHIBIT E—LIST OF AGREEMENTS RESTRICTING DEBT
EXHIBIT F—FORM OF CONFIDENTIALITY LETTER
EXHIBIT G—FORM OF GUARANTY
EXHIBIT H—FORM OF FUNDS DELIVERY INSTRUCTION LETTER

WESTERN GAS RESOURCES, INC.
12200 N. Pecos Street
Denver, CO 80234

As of December 19, 1991
(effective as of January 13, 2003)

To:

The Prudential Insurance Company of America ("PICA")
Pruco Life Insurance Company ("Pruco")
Prudential Investment Management, Inc. ("Prudential")
Each Prudential Affiliate (as hereinafter
defined) which becomes bound by certain
provisions of this Agreement as hereinafter provided
c/o Prudential Capital Group
Four Gateway Center
100 Mulberry Street
Newark, New Jersey 07102

SENIOR NOTES

Ladies and Gentlemen:

        The undersigned, Western Gas Resources, Inc. (the "Company"), hereby agrees with each Purchaser as follows:

PARAGRAPH 1. RESTATEMENT AND AMENDMENT; AUTHORIZATION OF ISSUE OF NOTES.

        1A.    Restatement and Amendment of Existing Agreement.    The Company and PICA entered into a Master Shelf Agreement dated as of December 19, 1991 as amended by Letter Amendment No. 1 dated October 22, 1992 (the "Original Agreement"). On July 22, 1993, the Company and PICA entered into an Amended and Restated Master Shelf Agreement which Amended and Restated the Original Agreement in its entirety. Such Amended and Restated Master Shelf Agreement was further amended by the Second Amended and Restated Master Shelf Agreement effective as of January 31, 1996. Such Second Amended and Restated Master Shelf Agreement has been amended by Letter Amendment No. 1 dated November 21, 1997, Letter Amendment No. 2 dated March 31, 1999, Limited Waiver, Consent, Release and Amendment No. 3 dated June 1, 1999, Limited Waiver, Consent, Release and Amendment No. 4 dated August 25, 2000, Letter Amendment No. 5 dated March 30, 2001 and Letter Amendment No. 6 dated March 1, 2002. (The Second Amended and Restated Master Shelf Agreement, as amended, is referred to herein as the "Existing Agreement"). The Company has issued to PICA or Prudential Affiliates $200,000,000 aggregate principal amount of Senior Notes (the "Original Notes") pursuant to the Existing Agreement thereby reducing the Available Facility Amount (as defined in the Existing Agreement) to zero. The Company, PICA, Pruco and Prudential are entering into this Agreement to, among other things, incorporate the amendments into the agreement and amend other provisions of the Existing Agreement including, without limitation, to increase the size of the Facility from zero to $65,000,000 and extend the period during which Notes may be issued. In connection with such increase and extension, PICA has agreed to relinquish its rights and obligations to administer the Facility to Prudential, and Prudential has agreed to accept such rights and obligations. In addition, PICA has agreed to relinquish its rights and obligations under the Intercreditor Agreement to Prudential, and Prudential has agreed to accept such rights and obligations. Accordingly, the Company, Prudential, PICA, Pruco and each Purchaser agrees that the Existing Agreement is hereby amended and restated in its entirety to read as provided in this Agreement.

        1B.    Authorization of Issue of Notes.    The Company has authorized and issued its senior promissory notes (the "Notes") in the aggregate principal amount of $265,000,000, dated the date of issue thereof, maturing, in the case of each Note so issued, no more than 12 years after the date of original issuance thereof (with an average life not in excess of 10 years), bearing interest on the unpaid balance thereof from the date thereof at the rate per annum, and having such other particular terms, as set forth, in the case of each Note so issued, in the Confirmation of Acceptance with respect to such Note delivered pursuant to paragraph 2F, and substantially in the form of Exhibit A-1 attached hereto. The term "Notes" as used herein shall include each Note delivered pursuant to any provision of this Agreement (including the Original Notes) and each Note delivered in substitution or exchange for any such Note pursuant to any such provision. Notes which have (i) the same final maturity, (ii) the same installment payment dates, (iii) the same installment payment amounts (as a percentage of the original principal amount of each Note), (iv) the same interest rate, and (v) the same interest payment periods, are herein called a "Series" of Notes. Capitalized terms used herein have the meanings specified in paragraph 10.

PARAGRAPH 2. PURCHASE AND SALE OF NOTES.

        2A.    Facility.    Prudential is willing to consider, in its sole discretion and within limits which may be authorized for purchase by the Prudential Affiliates from time to time, the purchase of Notes pursuant to this Agreement. The willingness of Prudential to consider such purchase of Notes is herein called the "Facility". At any time, the aggregate principal amount of Notes stated in paragraph 1, minus (i) the aggregate principal amount of Notes purchased and sold pursuant to this Agreement prior to such time (including the Original Notes) and (ii) the aggregate principal amount of Accepted Notes which have not yet been purchased and sold hereunder prior to such time, is herein called the "Available Facility Amount" at such time. Notwithstanding the willingness of Prudential to consider purchases of Notes by Prudential Affiliates, this Agreement is entered into on the express understanding that neither Prudential nor any other Prudential Affiliate shall be obligated to make or accept offers to purchase Notes, or to quote rates, spreads or other terms with respect to specific purchases of Notes, and the Facility shall in no way be construed as a capital commitment by Prudential or any Prudential Affiliate.

        2B.    Issuance Period.    Notes may be issued and sold pursuant to this Agreement until the earlier of (i) the Termination Date (or if such day is not a Business Day, the Business Day next preceding such day) and (ii) the thirtieth day after Prudential shall have given to the Company, or the Company shall have given to Prudential, a notice stating that it elects to terminate the issuance and sale of Notes pursuant to this Agreement (or if such thirtieth day is not a Business Day, the Business Day next preceding such thirtieth day). The period during which Notes may be issued and sold pursuant to this Agreement is herein called the "Issuance Period". The "Termination Date" shall be January 13, 2005.

        2C.    Spread Information.    Provided no Default or Event of Default exists, upon request by the Company on any Business Day during the Issuance Period if there is an Available Facility Amount on such Business Day, Prudential will, to the extent reasonably practicable, provide to the Company information (by telecopier or telephone) with respect to various spreads at which Prudential Affiliates might be interested in purchasing Notes of different average lives. The amount and content of information so provided shall be in the sole discretion of Prudential, but it is the intent of Prudential to provide information which will be of use to the Company in determining whether to initiate procedures for use of the Facility. Information so provided shall not constitute an offer to purchase Notes, and neither Prudential nor any Prudential Affiliate shall be obligated to purchase Notes at the spreads specified. Information so provided shall be representative of potential interest only for the period commencing on the day such information is provided and ending on the earlier of the fifth Business Day after such day and the first day after such day on which further spread information is provided. Prudential may suspend or terminate providing information pursuant to this paragraph 2C if, in its sole discretion, it determines that there has been an adverse change in the credit quality of the Company after the Effective Date.

        2D.    Request for Purchase.    The Company may from time to time during the Issuance Period make requests for purchases of Notes (each such request being a "Request for Purchase"). Each Request for Purchase shall be made to Prudential by telecopier or nationwide overnight delivery service, and shall (i) specify the aggregate principal amount of Notes covered thereby, which shall not be less than $10,000,000 and not be greater than the Available Facility Amount at the time such Request for Purchase is made, (ii) specify the principal amounts, final maturities, and installment payment dates and amounts of the Notes covered thereby, (iii) specify the use of proceeds of such Notes, (iv) specify the proposed day for the closing of the purchase and sale of such Notes, which shall be a Business Day during the Issuance Period not less than 10 Business Days and not more than 25 Business Days after the making of such Request for Purchase, (v) specify the number of the account and the name and address of the depository institution to which the purchase prices of such Notes are to be transferred on the Closing Day for such purchase and sale, (vi) certify that the representations and warranties contained in paragraph 8 are true on and as of the date of such Request for Purchase except to the extent of changes caused by the transactions herein contemplated and that there exists on the date of such Request for Purchase no Event of Default or Default, and (vii) be substantially in the form of Exhibit B attached hereto. Each Request for Purchase shall be in writing and shall be deemed made when received by Prudential.

        2E.    Rate Quotes.    Not later than five Business Days after the Company shall have given Prudential a Request for Purchase pursuant to paragraph 2D, Prudential may provide to the Company by telephone or telecopier, in each case between 9:30 A.M. and 1:00 P.M. New York City local time (or such later time as Prudential may elect), interest rate quotes for the several principal amounts, maturities and installment payment schedules (for Notes with average lives not to exceed 10 years) of Notes specified in such Request for Purchase. Each quote shall represent, the fixed interest rate per annum, payable on the outstanding principal balance of such Notes until such balance shall have become due and payable, at which a Prudential Affiliate would be willing to purchase such Notes at 100% of the principal amount thereof.

        2F.    Acceptance.    Within 30 minutes after Prudential shall have provided any interest rate quotes pursuant to paragraph 2E or such shorter period as Prudential may specify to the Company at any time, including the time at which the rate is quoted (such period being the "Acceptance Window"), the Company may, subject to paragraph 2G, elect to accept such interest rate quotes as to not less than $10,000,000 aggregate principal amount of the Notes specified in the related Request for Purchase. Such election shall be made by an Authorized Officer of the Company notifying Prudential by telephone or telecopier within the Acceptance Window that the Company elects to accept such interest rate quotes, specifying the Notes (each such Note being an "Accepted Note") as to which such acceptance (an "Acceptance") relates. The day the Company gives, and Prudential receives, notice of an Acceptance with respect to any Accepted Notes is herein called the "Acceptance Day" for such Accepted Notes. Any interest rate quotes as to which Prudential does not receive an Acceptance within the Acceptance Window shall expire, and no purchase or sale of Notes hereunder shall be made based on such expired interest rate quotes. Subject to paragraph 2G and the other terms and conditions hereof, (i) the Company agrees to sell to a Prudential Affiliate, and Prudential agrees to cause the purchase by a Prudential Affiliate of, the Accepted Notes as to which interest rate quotes shall have been provided to the Company for purchases by Prudential Affiliates at 100% of the principal amount of such Notes. Prior to the close of business on the Business Day next following the Acceptance Day, the Company and Prudential will execute a confirmation of such Acceptance substantially in the form of Exhibit C attached hereto (a "Confirmation of Acceptance").

        2G.    Market Disruption.    Notwithstanding the provisions of paragraph 2F, if Prudential shall have provided interest rate quotes pursuant to paragraph 2E and thereafter prior to the time notice of an Acceptance with respect to such quotes shall have been received by Prudential in accordance with paragraph 2F there shall occur a general suspension, material limitation, or significant disruption of trading in securities generally on the New York Stock Exchange or in the market for U.S. Treasury securities and other financial instruments, then such interest rate quotes shall expire, and no purchase or sale of Notes hereunder shall be made based on such expired interest rate quotes. If the Company thereafter notifies Prudential of the Acceptance of any such interest rate quotes, such Acceptance shall be ineffective for all purposes of this Agreement, and Prudential shall promptly notify the Company that the provisions of this paragraph 2G are applicable with respect to such Acceptance.

        2H.    Closing.

        2H(1).    Series H Closing.    The Company hereby agrees to sell to the Purchasers and, subject to the terms and conditions herein set forth, each Purchaser agrees to purchase from the Company under the Facility $25,000,000 of 6.36% Senior Notes, Series H, due 2008 (the "Series H Notes") in the aggregate principal amount set forth opposite its name on the Purchaser Schedule attached hereto at 100% of such aggregate principal amount. The Series H Notes shall be substantially in the form of Exhibit A-2 attached hereto. The Company will deliver to Prudential, at the offices of Prudential Capital Group at 2200 Ross Avenue, Suite 4200E, Dallas, Texas 75201, one or more Notes registered in the name of the Purchasers, evidencing the aggregate principal amount of Initial Notes to be purchased by the Purchasers and in the denomination or denominations specified in the Purchaser Schedule attached hereto against payment of the purchase price thereof by transfer of immediately available funds to the credit of the Company's account #0180352922 at Bank of America N.A., Dallas, Texas (ABA No. 111-000-012) on the date of closing, which shall be January 17, 2003, or any other date upon which the Company and Prudential may mutually agree in writing (the "Series H Closing").

        2H(2).    Subsequent Closings.    Not later than 11:30 A.M. (New York City local time) on the Closing Day for any Accepted Notes, the Company will deliver to each Purchaser listed in the Confirmation of Acceptance relating thereto at the offices of Prudential Capital Group, 2200 Ross Avenue, Suite 4200E, Dallas, Texas 75201 the Notes to be purchased by such Purchaser in the form of a single Accepted Note for the Accepted Notes which have exactly the same terms (or such greater number of Notes in authorized denominations as such Purchaser may request) dated the Closing Day and registered in such Purchaser's name (or in the name of its nominee), against payment of the purchase price thereof by transfer of immediately available funds for credit to the Company's account specified in the Request for Purchase of such Notes.

        2H(3).    Rescheduled Closings.    If the Company fails to tender to any Purchaser the Accepted Notes to be purchased by such Purchaser on the scheduled Closing Day for such Accepted Notes as provided above in this paragraph 2H, or any of the conditions specified in paragraph 3 shall not have been fulfilled by the time required on such scheduled Closing Day, the Company shall, prior to 1:00 P.M., New York City local time, on such scheduled Closing Day notify Prudential (which notification shall be deemed received by each Purchaser) in writing whether (x) such closing is to be rescheduled (such rescheduled date to be a Business Day during the Issuance Period not less than one Business Day and not more than 30 Business Days after such scheduled Closing Day (the "Rescheduled Closing Day") and certify to Prudential (which certification shall be for the benefit of each Purchaser) that the Company reasonably believes that it will be able to comply with the conditions set forth in paragraph 3 on such Rescheduled Closing Day and that the Company will pay the Delayed Delivery Fee in accordance with paragraph 2I(2) or (y) such closing is to be canceled as provided in paragraph 2I(3). In the event that the Company shall fail to give such notice referred to in the preceding sentence, Prudential (on behalf of each Purchaser) may at its election, at any time after 1:00 P.M., New York City local time, on such scheduled Closing Day, notify the Company in writing that such closing is to be canceled as provided in paragraph 2I(3).

        2I.    Fees.

        2I(1).    Facility Fee.    The Company will pay to Prudential in immediately available funds a fee (the "Facility Fee") on each Closing Day after the Series H Closing, in an amount equal to (i) 0.125% of the aggregate principal amount of Notes sold on such Closing Day.

        2I(2).    Delayed Delivery Fee.    If the closing of the purchase and sale of any Accepted Note is delayed for any reason (other than, with respect to any Accepted Note, because the Purchaser of such Accepted Note is prohibited by law from purchasing an Accepted Note or the Purchaser of such Accepted Notes shall request a delay in writing) beyond the original Closing Day for such Accepted Note, the Company will pay to the Purchaser which shall have agreed to purchase such Accepted Note, on the last Business Day of each calendar month, commencing with the first such day to occur more than 30 days after the Acceptance Day for such Accepted Note and ending with the last such day to occur prior to the Cancellation Date or the actual closing date of such purchase and sale, and on the Cancellation Date or actual closing date of such purchase and sale (if such Cancellation Date or closing date occurs more than 30 days after the Acceptance Day for such Accepted Note), a fee (the "Delayed Delivery Fee") equal to the product of (i) the amount determined by Prudential to be the amount by which the bond equivalent yield per annum of such Accepted Note exceeds the average investment rate per annum on a commercial paper investment of the highest quality selected by Prudential having a maturity date or dates the same as, or closest to, the Rescheduled Closing Day or Rescheduled Closing Days from time to time fixed for the delayed delivery of such Accepted Note, (ii) the principal amount of such Accepted Note, and (iii) a fraction the numerator of which is equal to the number of actual days elapsed from and including the 31st day after the Acceptance Day for such Accepted Note (in the case of the first such payment with respect to such Accepted Note) or from and including the date of the next preceding payment (in the case of any subsequent payment with respect to such Accepted Note) to but excluding the date of such payment, and the denominator of which is 360. In no case shall the Delayed Delivery Fee be less than zero. Nothing contained herein shall obligate any Purchaser to purchase any Accepted Note on any day other than the Closing Day for such Accepted Note, as the same may be rescheduled from time to time in compliance with paragraph 2H.

        2I(3).    Cancellation Fee.    If the Company at any time notifies the Purchaser obligated to purchase any Accepted Note in writing that the Company is canceling the closing of the purchase and sale of such Accepted Note, or if the Purchaser obligated to purchase any Accepted Note notifies the Company in writing under the circumstances set forth in the last sentence of paragraph 2H that the closing of the purchase and sale of such Accepted Note is to be canceled, or if the closing of the purchase and sale of such Accepted Note is not consummated on or prior to the last day of the Issuance Period (the date of any such notification, or the last day of the Issuance Period, as the case may be, being the "Cancellation Date"), the Company will, upon demand by such Purchaser pay such Purchaser in immediately available funds an amount (the "Cancellation Fee") equal to the price increase described in the next sentence (the "Price Movement") divided by 100 and multiplied by the principal amount of such Accepted Note. The Price Movement (expressed in decimals) shall be calculated by subtracting (a) the bid price at the time of the Acceptance on the Acceptance Day for such Accepted Note of U.S. Treasury securities having a maturity equal to or closest to the average life of such Accepted Note (as determined by Prudential) as reported on the Treasury Yield Monitor Page (or such other display as may replace the Treasury Yield Monitor Page), from (b) the ask price at 10:00 A.M. (New York City local time) on the Cancellation Date of such U.S. Treasury securities (as determined by Prudential in (a) above) as reported on the Treasury Yield Monitor Page (or such other display as may replace the Treasury Yield Monitor Page). Each price shall be based on a U.S. Treasury security having a par value of $100.00 and shall be rounded to the second decimal place. In no case shall the Cancellation Fee be less than zero.

        2I(4).    Structuring Fee.    The Company will pay to PICA a structuring fee of $75,000 on the Effective Date for amending and restating the Existing Agreement.

PARAGRAPH 3. CONDITIONS PRECEDENT.

        3A.    Conditions of Closing.    The obligation of any Purchaser to purchase and pay for any Accepted Notes, and the respective obligations of Prudential to cause the purchase of and payment by such Purchaser for any Accepted Notes, are subject to the satisfaction, on or before the Closing Day for such Accepted Notes, of the following conditions:

        3A(1).    Certain Documents.    Each Purchaser shall have received the following, each dated the Closing Day unless otherwise indicated:

        (i)    The Notes to be purchased by such Purchaser.

        (ii)  Certified copies of the resolutions of the Board of Directors of the Company authorizing the execution and delivery of this Agreement and the Company Pledge Agreement, and the issuance of the Notes, and of all documents evidencing other necessary corporate action and governmental approvals, if any, with respect to this Agreement, the Company Pledge Agreement and the Accepted Notes (provided that for any Closing Day occurring after the Series H Closing, the Company may certify that there has been no change to any applicable authorization or approval since the date on which it was most recently delivered to such Purchaser under this clause (ii) as an alternative to the further delivery thereof).

        (iii)  A certificate of the Secretary or an Assistant Secretary and one other officer of the Company certifying the names and true signatures of the officers of the Company authorized to sign this Agreement, the Company Pledge Agreement and the Notes and the other documents to be delivered hereunder (provided that for any Closing Day occurring after the Series H Closing, the Secretary or an Assistant Secretary and one other officer of the Company may certify that there has been no change to the officers of the Company authorized to sign Accepted Notes and other documents to be delivered therewith since the date on which a certificate setting forth the names and true signatures of such officers, as described above, was most recently delivered to such Purchaser under this paragraph 3A(1)(iii), as an alternative to the further delivery thereof).

        (iv)  Certified copies of the Certificate of Incorporation and By-laws of the Company (provided that for any Closing Day occurring after the Series H Closing, the Company may certify that there has been no change to any applicable constitutive document since the date on which it was most recently delivered to such Purchaser under this paragraph 3A(1)(iv), as an alternative to the further delivery thereof).

        (v)  Certified copies of the resolutions of the Board of Directors of each Guarantor authorizing the execution and delivery of such Guarantor's Guaranty and the MIGC Pledge Agreement, and of all documents evidencing other necessary corporate action and governmental approvals, if any, with respect to such Guaranties and the MIGC Pledge Agreement.

        (vi)  A certificate of the Secretary or an Assistant Secretary and one other officer of each Guarantor certifying the names and true signatures of the officers of such Guarantor authorized to sign such Guarantor's Guaranty and the MIGC Pledge Agreement and the other documents to be delivered hereunder.

        (vii) Certified copies of the Certificate of Incorporation and By-laws of each Guarantor.

        (viii)  A favorable opinion of John C. Walter, General Counsel of the Company, reasonably satisfactory to such Purchaser and substantially in the form of Exhibit D attached hereto and as to such other matters as such Purchaser may reasonably request. The Company hereby directs such counsel to deliver such opinion, agrees that the issuance and sale of any Accepted Notes will constitute a reconfirmation of such direction, and understands and agrees that each Purchaser receiving such an opinion will and is hereby authorized to rely on such opinion.

        (ix)  A certified copy of the NCNB Agreement and all amendments, modifications, consents or waivers with respect thereto.

        (x)  A certified copy of each guaranty or security agreement guarantying or securing the obligations of the Company under the NCNB Agreement and all amendments, modifications, consents or waivers with respect thereto.

        (xi)  A copy of each Guaranty dated the date of issue thereof, duly executed and delivered by each Guarantor.

        (xii) A copy of the Intercreditor Agreement dated the date of issue thereof, duly executed by each bank that is the beneficiary of a Bank Guaranty.

        3A(2).    Representations and Warranties; No Default.    The representations and warranties contained in paragraph 8 shall be true on and as of such Closing Day, except to the extent of changes caused by the transactions herein contemplated; there shall exist on such Closing Day no Event of Default or Default and no Default or Event of Default would result from the issuance of the Notes to be purchased on such Closing Day; and the Company shall have delivered to such Purchaser an Officer's Certificate, dated such Closing Day, to both such effects.

        3A(3).    Purchase Permitted by Applicable Laws.    The purchase of and payment for the Accepted Notes to be purchased by such Purchaser on the terms and conditions herein provided (including the use of the proceeds of such Notes by the Company) shall not violate any applicable law or governmental regulation (including, without limitation, Section 5 of the Securities Act or Regulation T, U or X of the Board of Governors of the Federal Reserve System) and shall not subject such Purchaser to any tax, penalty, liability or other onerous condition under or pursuant to any applicable law or governmental regulation, and such Purchaser shall have received such certificates or other evidence as it may reasonably request to establish compliance with this condition.

        3A(4).    Legal Matters.    Counsel for such Purchaser, including any special counsel for the Purchasers retained in connection with the purchase and sale of such Accepted Notes, shall be satisfied as to all legal matters relating to such purchase and sale, and such Purchaser shall have received from such counsel favorable opinions as to such legal matters as it may reasonably request.

        3A(5).    Proceedings.    All corporate and other proceedings taken or to be taken in connection with the transactions contemplated hereby and all documents incident thereto shall be reasonably satisfactory in substance and form to such Purchaser, and it shall have received all such counterpart originals or certified or other copies of such documents as it may reasonably request.

        3A(6).    Amendment of Credit Agreements.    The NCNB Agreement shall not require (or if so required, such conditions shall simultaneously terminate) (i) the grant of a Lien on any property of the Company or any Subsidiary (other than the Collateral) or (ii) the delivery of any security agreement or the guaranty or agreement to provide guaranties of the obligations of the Company under such agreements other than any Bank Guaranty which is subject to the Intercreditor Agreement and for which such Purchaser shall have received a Guaranty from the same Guarantor. In addition, such agreements shall not require that any lenders party thereto, or an agent or representative thereof, be named as beneficiary or loss payee on any insurance policy and all insurance policies of the Company and its Subsidiaries shall not name any such lender or agent as beneficiary or loss payee.

        3A(7).    Facility Fee Payment.    Prudential shall have received, within one Business Day of such Closing Day, the applicable Facility Fee for Notes to be issued on such Closing Day.

        3A(8).    Consent of Banks.    The Company shall have received any consent required by the NCNB Agreement and delivered a copy thereof to each Purchaser.

        3B.    Conditions to Effectiveness.    This Third Amended and Restated Master Shelf Agreement shall be effective as of January 13, 2003 (the "Effective Date") if, on or before January 17, 2003, of the conditions set forth in paragraph 3A for the Series H Closing and the following additional conditions have been satisfied:

        (i)    Each of the Company and MIGC shall have executed and delivered to Prudential an amendment to its Pledge Agreement in form and substance satisfactory to Prudential.

        (ii)  Each bank party to the NCNB Agreement and the agent thereunder shall have executed and delivered to Prudential an amended Intercreditor Agreement in form an substance satisfactory to Prudential.

        (iii)  PICA shall have received the structuring fee referred to in paragraph 2I(4).

        (iv)  The Company shall have delivered a Funds Delivery Instruction Letter in the form of Exhibit H hereto.

        (v)  The Guarantors shall have executed and delivered a Consent of Guarantors to this Third Amended and Restated Master Shelf Agreement in form and substance satisfactory to Prudential.

PARAGRAPH 4. PREPAYMENTS.

        4.    Prepayments.    The Notes shall be subject to prepayment only with respect to the required prepayments specified in paragraph 4A and the optional prepayments permitted by paragraph 4B.

        4A.    Required Prepayments.    Until the Notes of each Series shall be paid in full, the Company shall apply to the prepayment of the Notes of such Series, without premium, the principal amounts specified, if any, in each Note of such Series and such principal amounts of such Notes, together with interest thereon to the prepayment dates specified in such Notes, shall become due on such prepayment dates. The remaining principal amount of such Notes, together with interest accrued thereon, shall become due on the maturity date of such Notes.

        4B.    Optional Prepayment With Yield-Maintenance Amount

        4B(1).    Optional Prepayment At Any Time.    The Notes of each Series shall be subject to prepayment on or after 90 days from the date of issuance thereof, in whole at any time or from time to time in part (in multiples of $1,000,000), at the option of the Company, at 100% of the principal amount so prepaid plus interest and the Credit Fee thereon to the prepayment date and the Yield-Maintenance Amount, if any, with respect to each such Note. If the Company and the holder of any Note shall prior to the prepayment date designate in writing a different amount, the amount so designated shall be payable on the prepayment date in lieu of the Yield-Maintenance Amount with respect to such Note. Any partial prepayment of any such Notes pursuant to this paragraph 4B shall be applied in satisfaction of required payments of principal of such Notes in inverse order of their scheduled due dates.

        4B(2).    Special One Time Option to Prepay Series H Notes.    In addition to the optional prepayment set forth in paragraph 4B(1) above, the Series H Notes shall be subject to prepayment on January 18, 2005 in whole or in part, at the option of the Company, at 100% of the principal amount so prepaid plus interest and the Credit Fee thereon to the prepayment date without the Yield-Maintenance Amount.

        4C.    Notice of Optional Prepayment.    The Company shall give the holder of each Note to be prepaid pursuant to paragraph 4B irrevocable written notice of such prepayment not less than 10 Business Days prior to the prepayment date, specifying such prepayment date (which in the case of a prepayment pursuant to paragraph 4B(2) shall be January 17, 2005), specifying the aggregate principal amount of the Notes of the same Series as such Note to be prepaid on such date, identifying each Note held by such holder, and the principal amount of each such Note, to be prepaid on such date and stating that such prepayment is to be made pursuant to paragraph 4B. Notice of prepayment having been given as aforesaid, the principal amount of the Notes specified in such notice, together with interest and the Credit Fee thereon to the prepayment date and together with the Yield-Maintenance Amount, if any, herein provided, shall become due and payable on such prepayment date.

        4D.    Application of Prepayments.    In the case of each partial prepayment pursuant to paragraph 4A or 4B of all outstanding Notes of any Series, the principal amount to be prepaid shall be allocated to all Notes of such Series at the time outstanding (including, for the purpose of this paragraph 4D only, all Notes prepaid or otherwise retired or purchased or otherwise acquired by the Company or any of its Subsidiaries or Affiliates other than by prepayment pursuant to paragraph 4A or 4B) in proportion to the respective outstanding principal amounts thereof.

        4E.    Retirement of Notes.    The Company shall not, and shall not permit any of its Subsidiaries or Affiliates to, prepay or otherwise retire in whole or in part prior to their stated installment or final maturities (other than by prepayment pursuant to paragraph 4A or 4B or upon acceleration of such final maturity pursuant to paragraph 7A), or purchase or otherwise acquire, directly or indirectly, Notes held by any holder unless the Company or such Subsidiary or Affiliate shall have offered to prepay or otherwise retire or purchase or otherwise acquire, as the case may be, the same proportion of the aggregate principal amount of Notes held by each other holder of Notes at the time outstanding upon the same terms and conditions. Any Notes so prepaid or otherwise retired or purchased or otherwise acquired by the Company or any of its Subsidiaries or Affiliates shall not be deemed to be outstanding for any purpose under this Agreement, except as provided in paragraph 4D.

PARAGRAPH 5. AFFIRMATIVE COVENANTS.

        5.    Affirmative Covenants.    So long as any Note shall remain unpaid, the Company covenants that:

        5A.    Financial Statements.    The Company will deliver to the holder of each Note in duplicate:

        (i)    as soon as practicable and in any event within 45 days after the end of each quarterly period (other than the last quarterly period) in each fiscal year, a consolidating and consolidated statement of operations and statement of cash flows of the Company and its Subsidiaries for the period from the beginning of the current fiscal year to the end of such quarterly period, and a consolidating and consolidated balance sheet of the Company and its Subsidiaries as at the end of such quarterly period, setting forth in each case in comparative form figures for the corresponding period in the preceding fiscal year, all in reasonable detail and certified by an authorized financial officer of the Company, subject to changes resulting from year-end adjustments; provided, however, that delivery pursuant to clause (iv) below of copies of the Quarterly Report on Form 10-Q of the Company for such quarterly period filed with the Securities and Exchange Commission shall be deemed to satisfy the requirements of this clause (i) with respect to consolidated financial statements;

        (ii)  as soon as practicable and in any event within 90 days after the end of each fiscal year, a consolidating and consolidated statement of income and statement of cash flows of the Company and its Subsidiaries for such year, and a consolidating and consolidated balance sheet of the Company and its Subsidiaries as at the end of such year, setting forth in each case in comparative form corresponding consolidated figures from the preceding annual audit, all in reasonable detail and reasonably satisfactory in scope to the Required Holder(s) and, as to the consolidated statements, certified to the Company by independent public accountants of recognized standing selected by the Company whose certificate shall be in scope and substance reasonably satisfactory to the Required Holder(s) and, as to the consolidating statements, certified by an authorized financial officer of the Company; provided, however, that delivery pursuant to clause (iv) below of copies of the Annual Report on Form 10-K of the Company for such fiscal year filed with the Securities and Exchange Commission shall be deemed to satisfy the requirements of this clause (ii) with respect to consolidated financial statements;

        (iii)  as soon as practicable, and in any event within 105 days after the end of each fiscal year of MIGC, complete consolidated and consolidating (if applicable) financial statements of each of MIGC, MGTC and any other Subsidiary that owns or operates pipelines subject to state or federal rate regulation and has annual revenues in excess of $5,000,000 together with all notes thereto, prepared in reasonable detail in accordance with regulations promulgated by the Federal Energy Regulatory Commission in the case of MIGC and regulations promulgated by the Wyoming Public Service Commission in the case of MGTC, together with an opinion regarding MIGC, based on audits using generally accepted auditing standards, of independent certified public accountants of recognized standing stating that such consolidated financial statements have been so prepared; such consolidated financial statements shall contain a balance sheet as of the end of such fiscal year and statements of operations and cash flows, and of changes in stockholders' equity for such fiscal year, each setting forth in comparative form the corresponding figures for the preceding fiscal year;

        (iv)  promptly upon transmission thereof, copies of all such financial statements, proxy statements, press releases, notices and reports as it shall send to its public stockholders and copies of all registration statements (without exhibits) and all reports which it files with the Securities and Exchange Commission (or any governmental body or agency succeeding to the functions of the Securities and Exchange Commission);

        (v)  prior to April 30 in each year, a projection of the consolidated cash flows of the Company, its Subsidiaries and the joint ventures in which the Company or its Subsidiaries has an investment for the current fiscal year, in the form of Schedule 5A hereto;

        (vi)  as soon as delivered to such persons, all other reports, statements and notices delivered to (a) the agent, or the other lenders under the NCNB Agreement or (b) if the NCNB Agreement is no longer in effect, the lenders under the Company's major bank credit facility;

        (vii) as soon as practicable after receipt thereof, a copy of each other report submitted to the Company by independent accountants in connection with any annual, interim or special audit made by them of the books of the Company at any time during which the Company is not required to file periodic reports with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended; and

        (viii)  with reasonable promptness, such other information as the holder of any Note may reasonably request.

Together with each delivery of financial statements required by clauses (i) and (ii) above, the Company will deliver to the holder of each Note an Officer's Certificate demonstrating (with computations in reasonable detail) compliance by the Company and its Subsidiaries with the provisions of paragraphs 6A(1), 6A(2), 6A(3), 6A(4), 6A(5), 6B, 6C(1), 6C(2), 6C(3), 6C(4), 6C(5), 6C(6) and 6C(7) and stating that there exists no Event of Default or Default, or, if any Event of Default or Default exists, specifying the nature and period of existence thereof and what action the Company proposes to take with respect thereto. Together with each delivery of financial statements required by clause (ii) above, the Company will deliver to each holder of any Notes a certificate of such accountants stating that, in making the audit necessary to the certification of such financial statements, they have obtained no knowledge of any Event of Default or Default, or, if they have obtained knowledge of any Event of Default or Default, specifying the nature and period of existence thereof. Such accountants, however, shall not be liable to anyone by reason of their failure to obtain knowledge of any Event of Default or Default which would not be disclosed in the course of an audit conducted in accordance with generally accepted auditing standards.

        The Company also covenants that forthwith upon the chief executive officer, chief financial officer, Executive Vice President—General Counsel, Treasurer or President of the Company obtaining knowledge of an Event of Default or Default, it will deliver to each holder of any Notes an Officer's Certificate specifying the nature and period of existence thereof and what action the Company proposes to take with respect thereto.

        5B.    Inspection of Property.    The Company will permit any Person designated by the holder of any Note in writing, at such holder's expense, to visit and inspect any of the properties of the Company and its Subsidiaries while accompanied by personnel of the Company or a Subsidiary, to examine the corporate books and financial records of the Company and its Subsidiaries and make copies thereof or extracts therefrom and to discuss the affairs, finances and accounts of any of such corporations with the principal officers of the Company and its independent public accountants, all at such reasonable times and as often as such holder may reasonably request; provided, that each Person so designated by any holder to visit and inspect any properties shall, by virtue of such designation, be deemed to have agreed to comply with the Company's on-site safety procedures that are applicable to such properties. If at the time of any such inspection a Default or an Event of Default exists, the Company shall pay all reasonable out of pocket costs incurred by each holder in connection with such inspection.

        5C.    Covenant to Secure Notes Equally.    The Company covenants that, if it or any Subsidiary shall create or assume any Lien upon any of its property or assets, whether now owned or hereafter acquired, other than Liens permitted by the provisions of paragraph 6C(1) (unless prior written consent to the creation or assumption thereof shall have been obtained pursuant to paragraph 11C), it will make or cause to be made effective provision whereby the Notes will be secured by such Lien equally and ratably with any and all other Debt thereby secured so long as any such other Debt shall be so secured.

        5D.    Agreement Assuming Liability on Notes.    The Company covenants that, if at any time any Person should become liable (as co-obligor, endorser, guarantor or surety), on any other obligation of the Company or any obligation of any Subsidiary, (other than (i) obligations incurred in the ordinary course of business evidencing guaranties of gas purchases, transportation fees and construction contracts, (ii) surety bonds, appeal bonds and construction bonds (including bonds necessary for right-of-way condemnation and bonds issuable upon appeals of judgments or in relation to injunctions or temporary restraining orders (incurred in the ordinary course of business, (iii) letter of credit reimbursement obligations with respect to letters of credit issued in the ordinary course of business but not for borrowed money, and (iv) endorsements of negotiable instruments for collection in the ordinary course of business), the Company will, at the same time, cause such Person to deliver to each holder of Notes an agreement as shall be approved by the Required Holders pursuant to which such Person becomes similarly liable on the Notes.

        5E.    Notice of Material Events.    The Company will promptly notify each holder of the Notes of (i) any material adverse change in the Company's business, property or assets, financial condition or results of operations or the Company's consolidated financial condition, (ii) the acceleration of the maturity of any indebtedness owed by the Company or any of its Subsidiaries or any default by the Company or any of its Subsidiaries under any indenture, mortgage, agreement, contract or other instrument to which any of them is a party or by which any of them or any of their properties is bound, if such acceleration or default would have a material adverse effect upon the Company's consolidated business, property or assets, financial condition or results of operations, (iii) any material adverse claim (or any claim of $5,000,000 or more) asserted against the Company or any of its Subsidiaries or with respect to the Company's or any Subsidiary's properties, (iv) the occurrence of any Termination Event or of any event or condition known to the Company which might adversely affect the enforceability of this Agreement or any Note and (v) the filing of any suit or proceeding against the Company or any of its Subsidiaries in which an adverse decision could have a material adverse effect upon the Company's or any Subsidiary's business, property or assets, financial condition, or results of operations. Upon the occurrence of any of the foregoing the Company will, and will cause each such Subsidiary to, take all necessary or appropriate steps to remedy promptly any such material adverse change, Default, Event of Default or default, to protect against any such adverse claim, to defend any such suit or proceeding, to remedy any such Termination Event or event affecting enforceability, and to resolve all controversies on account of any of the foregoing.

        5F.    Maintenance of Properties.    The Company will, and will cause each of its Subsidiaries to, maintain, preserve, protect and keep all material property used or useful in the conduct of its business in good condition and in compliance with all applicable laws, rules and regulations and will from time to time make all repairs, renewals and replacements needed to enable the business and operations carried on in connection therewith to be promptly and advantageously conducted at all times.

        5G.    Maintenance of Existence and Qualifications.    The Company will, and will cause each of its Subsidiaries to, maintain and preserve its corporate existence and its rights and franchises in full force and effect and will qualify to do business as a foreign corporation in all states or jurisdictions where required by applicable law, except where the failure so to qualify will not have any material adverse effect on the business, property or assets, financial condition or results of operations of the Company and its Subsidiaries, taken as a whole.

        5H.    Insurance.    The Company will, and will cause each of its Subsidiaries and each of its Affiliates that is controlled by the Company or its Subsidiaries to, maintain insurance with responsible and reputable insurance companies or associations in such amounts covering such risks as is usually carried by companies of similar size as the Company engaged in similar businesses and owning similar properties in the same general areas in which the Company or such Subsidiary or Affiliates operates.

        5I.    Compliance with Agreements and Law.    The Company will, and will cause each of its Subsidiaries and each of its Affiliates that is controlled by the Company or its Subsidiaries to, perform all material obligations it is required to perform under the terms of each indenture, mortgage, deed of trust, security agreement, lease, franchise, agreement, contract or other instrument or obligation to which it is a party or by which it or any of its properties is bound. The Company will, and will cause each of its Subsidiaries and each of its Affiliates that is controlled by the Company or its Subsidiaries to, conduct its business and affairs in compliance with all laws, regulations, and orders applicable thereto, such compliance to include, without limitation, paying before the same become delinquent all taxes, assessments and governmental charges imposed upon it or upon its property except to the extent contested in good faith by appropriate proceedings and for which adequate reserves have been established in accordance with generally accepted accounting principles except where noncompliance would not materially adversely affect the business, property or assets, financial condition or results of operations of the Company and its Subsidiaries, taken as a whole.

        5J.    Compliance with Environmental Laws.    The Company will, and will cause each of its Subsidiaries and each of its Affiliates that are controlled by the Company or its Subsidiaries to, comply in a timely fashion with, or operate pursuant to valid waivers of the provisions of, all applicable federal, state and local environmental or pollution-control laws, regulations, orders and decrees governing, without limitation, the emission of wastewater effluent, solid and hazardous waste and air pollution, and setting forth general environmental conditions together with any other applicable requirements for conducting, on a timely basis, periodic tests and monitoring for contamination of ground water, surface water, air and land and for biological toxicity of the aforesaid, and diligently comply with the applicable regulations (except to the extent such regulations are waived by appropriate governmental authorities) of the Environmental Protection Agency or other relevant federal, state or local governmental authority except where noncompliance would not materially adversely affect the business, property or assets, financial condition or results of operations of the Company and its Subsidiaries, taken as a whole. The Company shall not be deemed to have breached or violated the preceding sentence of this paragraph 5J if the Company, any Subsidiary or any Affiliate of the Company is challenging in good faith by appropriate proceedings diligently pursued the application or enforcement of any such governmental requirements for which adequate reserves have been established in accordance with generally accepted accounting principles. TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE COMPANY AGREES TO INDEMNIFY AND HOLD EACH HOLDER OF NOTES AND THEIR RESPECTIVE OFFICERS, AGENTS AND EMPLOYEES HARMLESS FROM ANY LOSS, LIABILITY, CLAIM OR EXPENSES THAT SUCH HOLDER MAY INCUR OR SUFFER AS A RESULT OF A BREACH BY THE COMPANY, ITS SUBSIDIARIES OR AFFILIATES, AS THE CASE MAY BE, OF THIS COVENANT.

        5K.    Information Required by Rule 144A.    The Company will, upon the request of the holder of any Note, provide such holder, and any qualified institutional buyer designated by such holder, such financial and other information as such holder may reasonably determine to be necessary in order to permit compliance with the information requirements of Rule 144A under the Securities Act in connection with the resale of Notes, except at such times as the Company is subject to and in compliance with the reporting requirements of Section 13 or 15(d) of the Exchange Act. For the purpose of this paragraph 5K, the term "qualified institutional buyer" shall have the meaning specified in Rule 144A under the Securities Act.

        5L.    ERISA.    The Company will promptly pay and discharge, and will cause its Subsidiaries promptly to pay and discharge, all obligations and liabilities arising under ERISA of a character which if unpaid or unperformed might result in the imposition of a lien against any of its property and will promptly notify the holder of each Note of (i) the occurrence of any reportable event (as defined in ERISA) which might result in the termination by the PBGC of any Plan covering any officers or employees of the Company of any Subsidiary, any benefits of which are, or are required to be, guaranteed by the PBGC, (ii) receipt of any notice from the PBGC of its intention to seek termination of any such Plan or appointment of a trustee therefor, and (iii) its intention to terminate or withdraw from any Plan. The Company will not, and will not permit any Subsidiary to, terminate any such Plan or withdraw therefrom unless it shall be in compliance with all of the terms and conditions of this Agreement after giving effect to any liability to the PBGC resulting from such termination or withdrawal.

        5M.    Guaranties.    The Company will require each Subsidiary, and each entity that would constitute a Subsidiary but for its being organized under the laws of a jurisdiction outside the United States of America, that guarantees any obligations of the Company under any Debt, or under any replacement or refinancing thereof, immediately to execute and deliver a Guaranty, or if such Subsidiary or entity shall have previously executed and delivered a Guaranty which has been subsequently released by the Required Holder(s), to execute and deliver a new Guaranty, to the holder of each Note. The Company will cause each such Subsidiary or other entity to deliver to the holder of each Note, simultaneously with its delivery of such Guaranty, written evidence satisfactory to the Required Holder(s) and their counsel that such Subsidiary or other entity has taken all corporate or similar action necessary to duly approve and authorize its execution, delivery and performance of such Guaranty and other documents which it is required to execute.

        5N.    Pledge of Subsidiary Stock.    The Company granted a security interest in the stock of all of its Subsidiaries who are Guarantors and Western Power Services, Inc. to PICA, as collateral agent for the holders of the Notes. As of the Effective Date, the Company and the holders of the Notes and Prudential amended the Company Pledge Agreement to reflect that Prudential is the successor collateral agent for the holder of the Notes. The holders and the Company agree that all stock and other securities pledged pursuant to the Pledge Agreements will remain subject to the Pledge Agreements until (i) in the case of all such stock and other securities, the Company achieves the Minimum Rating and NCNB, as agent for the lenders under the NCNB Agreement, have released their security interests in all of such pledged stock and other securities and, provided that no Default or Event of Default exists or would result therefrom. If, however, after any release described in the preceding sentence the Company is downgraded below the Minimum Rating, the Company shall immediately pledge, and cause its Subsidiaries to pledge, all stock or other equity interests in all Guarantors and Western Power Services, Inc., to the holders of the Notes under one or more Pledge Agreements.

        5O.    Credit Fee.    The Company shall pay the holder of each Note a credit fee equal to 0.50% per annum of the principal amount of such Note during the period beginning January 1, 1999 (with such credit fee accruing as if it had been in effect, continuously, beginning January 1, 1999), through the day on which the Company provides to such holder satisfactory evidence that the Company has received the Minimum Rating or achieved the Required Debt Ratio. If the Company is downgraded below the Minimum Rating after having received the Minimum Rating and at such time does not have the Required Debt Ratio, the Company shall pay the holder of each Note a credit fee equal to 0.50% per annum of the outstanding principal amount of such Note, in respect to such principal amount, during the period beginning the day after the Company loses the Minimum Rating and ending on the day the Company again provides satisfactory evidence to the holder of such Note that the Company has received the Minimum Rating or has once again achieved the Required Debt Ratio (the credit fees applicable pursuant to the preceding two sentences are referred to herein as the "Credit Fee"). The Credit Fee shall be payable quarterly in arrears on the last day of March, June, September and December of each year commencing March 31, 1999. The Company represents that, as of the Effective Date, it has achieved the Required Debt Ratio and will pay the accrued Credit Fee on the Effective Date.

PARAGRAPH 6. NEGATIVE COVENANTS.

        6.    Negative Covenants.    So long as any Note shall remain unpaid, the Company covenants that:

        6A.    Financial Covenants.    The Company will not permit:

        6A(1).    Consolidated Tangible Net Worth.    Consolidated Tangible Net Worth at any time on or after January 1, 1999 to be less than the sum of (i) $300,000,000 plus (ii) an amount equal to 50% of Consolidated Net Earnings earned from January 1, 1999 (to the extent such amount is a positive number) plus (iii) an amount equal to 75% of the net proceeds of any equity offerings after January 1, 1999.

        6A(2).    Total Debt Maintenance.    The sum of Consolidated Debt plus Excess Lease Payments at any time to exceed 55% of the sum of Consolidated Net Tangible Assets plus Excess Lease Payments. In any event, for purposes of determining compliance with this paragraph 6A(2), Consolidated Debt shall include without duplication and without limitation all indebtedness included in determining compliance with the similar covenant in the NCNB Agreement.

        6A(3).    Senior Debt Maintenance.    Subject to paragraph 11Q, the sum of Consolidated Senior Debt plus Excess Lease Payments at any time to exceed 35% of the sum of Consolidated Net Tangible Assets plus Excess Lease Payments. In any event, for purposes of determining compliance with this paragraph 6A(3), Consolidated Senior Debt shall include without duplication and without limitation all indebtedness included in determining compliance with the similar covenant in the NCNB Agreement.

        6A(4).    Total Fixed Charge Coverage Ratio.    For each fiscal quarter of the Company, the ratio of (i) the sum of (a) the Consolidated Net Earnings of the Company for the four immediately preceding fiscal quarters of the Company plus (b) the Company's consolidated interest expense, and provision for income taxes, depreciation and amortization for the four immediately preceding fiscal quarters of the Company that were taken into account in determining such Consolidated Net Earnings to (ii) the Company's consolidated accrued interest expense for the four immediately preceding fiscal quarters to be less than (x) 2.50 to 1.00 from the Effective Date through December 30, 2002 and (y) 3.25 to 1.00 from December 31, 2002 and at any time thereafter.

        6A(5).    Consolidated Senior Debt to EBITDA.    As of any date of determination from and after January 1, 2000, the ratio of the sum of Consolidated Senior Debt plus Excess Lease Payments to EBITDA for the period of four fiscal quarters most recently ended to be greater than 4.00 to 1.00.

        6B.    Dividend Limitation.    The Company will not make any Restricted Payment except out of Consolidated Net Earnings Available for Restricted Payments and unless no Default or Event of Default exists before such Restricted Payment is made and no Default or Event of Default would exist immediately after such Restricted Payment is made.

        6C.    Lien, Debt, and Other Restrictions.    The Company will not and will not permit any Subsidiary to:

        6C(1).    Liens.    Create, assume or suffer to exist any Lien upon any of its properties or assets, whether now owned or hereafter acquired (whether or not provision is made for the equal and ratable securing of the Notes in accordance with the provisions of paragraph 5C), except

        (i)    Liens for taxes not yet due or which are being actively contested in good faith by appropriate proceedings,

        (ii)  other statutory Liens incidental to the conduct of its business or the ownership of its property and assets (including landlord liens) that are not incurred in connection with the borrowing of money or the obtaining of advances or credit or guaranteeing the obligations of a Person, and which do not in the aggregate materially detract from the value of its property or assets or materially impair the use thereof in the operation of its business,

        (iii)  Liens on property or assets of a Subsidiary to secure obligations of such Subsidiary to the Company or a Wholly Owned Subsidiary,

        (iv)  existing Liens on property of the Company described in Schedule 6C(2) attached hereto and securing Debt permitted by clause (iii) of paragraph 6C(2),

        (v)  in the case of transactions that occur after the date hereof, Liens existing on any real property of any corporation at the time it becomes a Subsidiary, or existing prior to the time of acquisition upon any property acquired by the Company or any Subsidiary through purchase, merger or consolidation or otherwise, whether or not assumed by the Company or such Subsidiary, or placed on property at the time of acquisition by the Company or any Subsidiary to secure all or a portion of (or to secure Debt incurred to pay all or a portion of) the purchase price thereof, provided that (a) all of such property is not or shall not thereby become encumbered in any amount in excess of the lesser of the cost thereof or Fair Market Value thereof and (b) any such Lien shall not encumber any other property of the Company or such Subsidiary,

        (vi)  Liens on deposit and other bank accounts of the Company created by the right of a lender party to the NCNB Agreement to offset obligations of the Company owing under such agreements, respectively, against such accounts if, and only if, there is no agreement between any such lender and the Company which requires the Company to maintain any deposit or other funds in any account with such lender other than as provided in (vii) below,

        (vii) Liens on deposits of the Company under the NCNB Agreement to secure the face amount of outstanding letters of credit issued pursuant to the NCNB Agreement,

        (viii)  Liens created by the Pledge Agreement and the pledge agreements in favor of NCNB as collateral agent for the lenders under the NCNB Agreement encumbering the Collateral so long as the Intercreditor Agreement is in effect, and

        (ix)  other Liens on the property of the Company,

provided that the aggregate amount of Debt secured by Liens permitted by clauses (iv), (v) and (ix), together with the amount of undrawn letters of credit subject to the obligation to provide deposits referred to in clause (vii), whether or not such deposits have been provided, does not exceed at any time an amount in excess of 5% of Consolidated Tangible Net Worth.

        6C(2).    Debt.    Create, incur, assume or suffer to exist any Debt, except

        (i)    Debt of the Company represented by the Notes,

        (ii)  Debt of the Company and any Subsidiary secured by Liens permitted by the provisions of clause (v) of paragraph 6C(1) provided that the aggregate amount of such Debt together with all other Debt secured by Liens permitted by paragraphs 6C(1)(iv), 6C(1)(ix) and the amount of undrawn letters of credit permitted by 6C(1)(vii) does not exceed at any time an amount equal to 5% of Consolidated Tangible Net Worth,

        (iii)  Debt of the Company described in Schedule 6C(2) attached hereto which shall not be renewed, extended or permitted to remain outstanding after the stated maturities thereof,

        (iv)  Debt of any Subsidiary to the Company or any other Wholly Owned Subsidiary, provided that such Debt shall not be subordinated to any other obligation of such Subsidiary,

        (v)  other Debt of the Company not prohibited by paragraphs 6A(2), 6A(3) or 6A(5), and

        (vi)  Debt of the Guarantors represented by the Bank Guaranties, the Guaranties and the Subordinated Debt Guaranties.

        6C(3).    Limitation on Investments and New Businesses.    (i) Make any expenditure or commitment or incur any obligation or enter into or engage in any transaction except in the ordinary course of business (which shall be deemed to include expenditures, commitments, obligations and transactions permitted by clause (iii) or clause (iv) of this paragraph 6C(3)); (ii) engage directly or indirectly in any business or conduct any operations except in connection with or incidental to its present businesses and operations (which shall be deemed to include electric power generation and marketing and expenditures, commitments, obligations and transactions permitted by clause (iii) or clause (iv) of this paragraph 6C(3)); (iii) make any acquisitions of, capital contributions to, or other investments in, any Persons which exceed in the aggregate $500,000 other than (a) capital contributions to and investments in any joint venture described in Schedule 6C(3) or in the Wholly Owned Subsidiaries, (b)  acquisitions of equity in corporations or partnerships having as their primary business gas processing, transmission and gathering, oil and gas production and storage or gas marketing and related activities or electric power generation or marketing which do not exceed in the aggregate 10% of Consolidated Net Tangible Assets, (c) deposits with, investments in obligations of and time deposits in any domestic bank or domestic branches of foreign banks which, at the time such deposit or investment is made, are rated A or better by S & P or Moody's and investments maturing within one year from the date of acquisition in direct obligations of or obligations supported by, the full faith and credit of, the United States of America and (d) purchases of open market commercial paper, maturing within 270 days after acquisition thereof, with the highest or second highest credit rating given by either S & P or Moody's and investments in money market mutual funds with equivalent ratings or (iv) make any significant acquisitions or investments in any properties other than gas processing, transmission and gathering facilities, domestic oil and gas properties, gas storage facilities, gas inventory and electric power generation facilities which exceeds $5,000,000; provided, however, that the loans referred to in clause (iii) of paragraph 6C(7) may be outstanding.

        6C(4).    Sale of Stock and Debt of Subsidiaries.    Sell or otherwise dispose of, or part with control of, any shares of stock or Debt of any Subsidiary, except to the Company or another Wholly Owned Subsidiary, and except that all shares of stock and Debt of any Subsidiary at the time owned by or owed to the Company and all Subsidiaries may be sold as an entirety for a cash consideration which represents the fair value (as determined in good faith by the Board of Directors of the Company) at the time of sale of the shares of stock and Debt so sold, provided that (i) the assets of such Subsidiary together with (ii) the assets of all other Subsidiaries the stock or Debt of which was sold or otherwise disposed of in the preceding 12-month period and (iii) the assets of the Company and its Subsidiaries sold, leased, transferred or otherwise disposed of pursuant to clause (v) of paragraph 6C(5) in the preceding 12-month period (in each transaction measured by the greater of book value or Fair Market Value), do not represent more than 15% of Consolidated Net Tangible Assets as reflected on the most recent annual or quarterly consolidated balance sheet, and provided further that, at the time of such sale, such Subsidiary shall not own, directly or indirectly, any shares of stock or Debt of, or any other continuing investment in any other Subsidiary (unless all of the shares of stock and Debt of such other Subsidiary owned, directly or indirectly, by the Company and all Subsidiaries are simultaneously being sold as permitted by this paragraph 6C(4)), or any shares of stock or Debt of the Company.

        6C(5).    Merger and Sale of Assets.    Merge or consolidate with or into any other Person or sell, convey, lease, transfer or otherwise dispose of all or any part of its assets, except that:

        (i)    (a) any Subsidiary may merge with the Company (provided, that the Company shall be the continuing or surviving corporation) and (b) any Subsidiary may merge with a Wholly Owned Subsidiary (provided that the Wholly Owned Subsidiary shall be the continuing or surviving corporation),

        (ii)  any Subsidiary may sell, lease, transfer or otherwise dispose of any of its assets to the Company or to a Wholly Owned Subsidiary,

        (iii)  the Company may merge with any other corporation, provided that (a) the Company shall be the continuing or surviving corporation, and (b) immediately after giving effect to such merger no Event of Default or Default shall exist,

        (iv)  any non Wholly Owned Subsidiary may merge or consolidate with any other corporation, provided, that immediately after giving effect to such merger or consolidation (a) the continuing or surviving corporation of such merger or consolidation shall constitute a Subsidiary, and (b) no Event of Default or Default shall exist,

        (v)  the Company or any Subsidiary may sell, lease, transfer or otherwise dispose of any of its assets to any Person, provided, that (a) such assets together with (b) all other assets of the Company and its Subsidiaries sold, leased, transferred or otherwise disposed of during the preceding 12 month period, and (c) the assets of all Subsidiaries, the stock or Debt of which has been sold or otherwise disposed of during the preceding 12-month period pursuant to the first proviso of paragraph 6C(4) (in each transaction measured by the greater of book value or Fair Market Value), do not represent more that 15% of Consolidated Net Tangible Assets as reflected on the most recent annual or quarterly consolidated balance sheet,

        (vi)  the Company may merge into or consolidate with any solvent corporation if (x) the surviving corporation is a corporation organized under the laws of any State of the United States of America, (y) such corporation shall expressly assume by an agreement satisfactory in substance and form to the Required Holder(s) (which agreement may require the delivery in connection with such assumption of such opinions of counsel as the Required Holder(s) may reasonably require), all of the obligations of the Company under this Agreement and the Notes, including all covenants herein and therein contained, and such successor or acquiring corporation shall succeed to and be substituted for the Company with the same effect as if it had been named herein as a party hereto (it being agreed that such assumption shall, upon the request of the holder of any outstanding Note and at the expense of such successor corporation, be evidenced by the exchange of such Note for another Note executed by such successor corporation, with such changes in phraseology and form as may be appropriate but in substance of like terms as the Note surrendered for such exchange and of like unpaid principal amount, and that each Note executed pursuant to paragraph 11D after such assumption shall be executed by and in the name of such successor corporation) and (z) after giving effect to such merger or consolidation no Event of Default or Default shall exist, and

        (vii) the Company and any Subsidiary may sell or otherwise dispose of inventory in the ordinary course of business.

        6C(6).    Lease Rentals.    Except for oil, gas and mineral leases, real estate leases for office space used by the Company, and except for leases for transportation equipment, including over-the-road trucks and tankers, data processing and other office equipment used in the ordinary course of business, enter into or permit to remain in effect, any agreements to rent or lease (as lessee) any real or personal property if after giving effect thereto the aggregate amount of all sums payable by the Company and all Subsidiaries over the remaining lives of all such leases in the aggregate would exceed $75,000,000.

        6C(7).    Limitation on Credit Extensions.    Extend credit, make advances or make loans other than (i) normal and prudent extensions of credit in the ordinary course of business, which extensions shall not be for longer periods than those extended by similar businesses operated in a normal and prudent manner and (ii) loans from Wholly Owned Subsidiaries to the Company, and loans from Wholly Owned Subsidiaries or the Company to any Subsidiary, in each case made in the ordinary course of business and, in the case of loans from Wholly Owned Subsidiaries that are not Guarantors which are made to the Company or a Subsidiary that is a Guarantor, subordinated to the principal of, interest on, Credit Fee and Yield-Maintenance Amount, if any, with respect to the Notes.

        6C(8).    Contracts; Take-or-Pay Agreements.    Enter into any "take-or-pay" contract or other contract which requires it to pay for oil, gas, other hydrocarbons or other minerals prior to taking delivery thereof, provided that the Company may enter into such contracts so long as the aggregate maximum direct and contingent liability of the Company under such contracts does not exceed $500,000 at any one time, and provided further that the Company may enter into contracts with gas producers requiring the Company to make payments if the Company has not connected the producer's well to the Company's gathering system within a specified period of time so long as the maximum direct or contingent liability of the Company under such contract does not exceed $500,000. The Company and its Subsidiaries may enter into: (a) Short Hedge Futures to sell natural gas or liquid hydrocarbons or to offset a Long Hedge Future; and (b) Long Hedge Futures to purchase natural gas or liquid hydrocarbons or to offset a Short Hedge Future; provided, however, that at the time of entering into a Short Hedge Future, the Company shall own and have available to it sufficient amounts of natural gas or liquid hydrocarbons, as the case may be, or shall own pursuant to firm contracts to deliver natural gas or liquid hydrocarbons, as the case may be, pursuant to such Short Hedge Future; provided, further, that at the time of entering into a Long Hedge Future, the Company shall have sufficient agreements from Counterparties to purchase natural gas or liquid hydrocarbons, as the case may be, from the Company so that the Company can resell natural gas or liquid hydrocarbons, as the case may be, delivered pursuant to such Long Hedge Future.

        6C(9).    Sale or Discount of Receivables.    Sell with recourse, or discount (other than to the extent of finance and interest charges included therein) or otherwise sell for less than face value thereof, any of its notes or accounts receivable except notes or accounts receivable the collection of which is doubtful in accordance with generally accepted accounting principles.

        6C(10).    Guaranties.    Enter into or be party to:

        (i)    any contract for the purchase of materials, supplies or other property or services if such contract (or any related document) requires that payment for such materials, supplies or other property or services shall be made regardless of whether or not delivery of such materials, supplies or other property or services is ever made or tendered, or

        (ii)  any contract to rent or lease (as lessee) any real or personal property if such contract (or any related document) provides that the obligation to make payments thereunder is absolute and unconditional under conditions not customarily found in commercial leases then in general use or requires that the lessee purchase or otherwise acquire securities or obligations of the lessor, or

        (iii)  any contract for the sale or use of materials, supplies or other property, or the rendering of services, if such contract (or any related document) requires that payment for such materials, supplies or other property, or the use thereof, or payment for such services, shall be subordinated to any indebtedness (of the purchaser or user of such materials, supplies or other property or the Person entitled to the benefit of such services) owed or to be owed to any Person, or

        (iv)  any other contract that is a guaranty, an endorsement or another form of contingent liability in respect of the obligations, stock or dividends of any Person or that, in economic effect, is substantially equivalent to a guaranty (other than the guaranties permitted by clause (vi) of paragraph 6C(2)); provided, that the foregoing provisions shall not apply to endorsements of negotiable instruments for collection in the ordinary course of business;

provided, that, notwithstanding the foregoing, any contract of the type specified in any of the provisions of this paragraph 6C(10) shall be permitted if the obligations of the Company or such Subsidiary, as the case may be, thereunder constitute Debt of the type described in clause (iv) of the definition thereof and such Debt were permitted by the Debt limitations contained in paragraphs 6A(2), 6A(3) and 6A(5).

        6C(11).    Transactions With Affiliates.    Directly or indirectly, purchase, acquire or lease any property from, or sell, transfer or lease any property to, or otherwise deal with, in the ordinary course of business or otherwise (i) any Affiliate, (ii) any Person owning, beneficially or of record, directly or indirectly, either individually or together with all other Persons to whom such Person is related by blood, adoption or marriage, stock of the Company (of any class having ordinary voting power for the election of directors) aggregating 5% or more of such voting power or (iii) any Person related by blood, adoption or marriage to any Person described or coming within the provisions of clause (i) or (ii) of this paragraph 6C(11), provided that the Company may sell to, or purchase (within the limitations of paragraph 6B) from, any such Person shares of the Company's stock and except for transactions that are otherwise permitted by this Agreement and that are in the ordinary course of the Company's or a Subsidiary's business, and are also upon fair and reasonable terms no less favorable to the Company or such Subsidiary than it would obtain in a comparable arm's-length transaction with a Person not an Affiliate.

        6C(12).    Certain Matters Relating to Subordinated Debt.    (i) Make any payment in respect of principal of, or purchase, redeem or otherwise retire, any Subordinated Debt (including, without limitation, by the making of payments by Subsidiaries under Subordinated Guaranties) if a Default or an Event of Default at the time exists or would result therefrom or (ii) issue, create or incur any Subordinated Debt if a "Default" (as such term is defined in the NCNB Agreement) at the time exists or would result therefrom.

        6D.    Issuance of Stock by Subsidiaries.    The Company covenants that it will not permit any Subsidiary to issue, sell or dispose of any shares of its stock of any class except to the Company or a Wholly Owned Subsidiary, and except to the extent that holders of minority interests may be entitled to purchase stock by reason of preemptive rights.

        6E.    Other Agreements.

        6E(1).    Modifications.    The Company will not amend or modify: (i) any term or provision of the NCNB Agreement so as to change to an earlier date the date on which any payment of principal is to be made thereunder or (ii) any term or provision of the NCNB Agreement so as to shorten the duration or increase the amount of any commitment thereunder; provided, that the Company may increase the interest rate or fees payable under or with respect to the NCNB Agreement if the Company complies with the other provisions of this Agreement.

        6E(2).    Conflicting Provisions.    The Company will not and will not permit any of its Subsidiaries to enter into or permit to exist any agreement to which any such entity is a party or by which any such entity is bound (i) which would cause a Default or Event of Default hereunder, (ii) which contains any provision which would be violated or breached by the performance of the obligations of the Company and its Subsidiaries under this Agreement, any Guaranty, any Pledge Agreement or any other agreement, document, instrument or writing executed in connection therewith or (iii) which contains any provision that attempts to modify, amend or restrict any of the rights or remedies of the holders of the Notes hereunder or under the Intercreditor Agreement, the Notes, the Guaranties or the Pledge Agreements. The Company will not and will not permit any of its Subsidiaries to enter into or suffer to exist any contractual obligation, other than this Agreement, the Guaranties and the Pledge Agreements, which restricts the ability (i) of the Company to make any prepayments of the Notes required under this Agreement, (ii) of the Company to make any payments required under this Agreement or of any Subsidiary to make any payments required under any Guaranty, (iii) of any Subsidiary to make any dividends or distributions to the Company or a Wholly Owned Subsidiary, (iv) of any Subsidiary to otherwise transfer any of its property or assets to the Company or a Wholly Owned Subsidiary, (v) of any Subsidiary to make any payments in respect of Debt owed by a Subsidiary to the Company or a Wholly Owned Subsidiary, or (vi) of any Subsidiary to make any loan, advance or extension of credit to the Company or a Wholly Owned Subsidiary.

        6F.    Restrictions on Hedging Transactions.    The Company will not and will not permit any Subsidiary to enter into Hedging Transactions with respect to crude oil, natural gas or liquid hydrocarbons other than Hedging Transactions (i) that apply to not more than the Adjusted Equity Gas Volume in any calendar year and (ii) for the succeeding three calendar years; provided, however, that this paragraph 6F shall not prevent the Company and its Subsidiaries from entering into Hedging Transactions with respect to 100% of the natural gas of the Company or its Subsidiaries (a) held in storage facilities owned by the Company or its Subsidiaries or (b) purchased from third parties and sold to third parties in connection with the marketing operations of the Company and its Subsidiaries. "Adjusted Equity Gas Volume" for any calendar year, shall mean the volumes of natural gas and liquid hydrocarbons owned by the Company and its Subsidiaries either through ownership of interests in oil and gas properties ("ownership interests") or pursuant to contractual gathering and processing agreements ("contractual arrangements") that, (x) in the case of ownership interests, do not exceed 75% of proved developed producing reserves to be produced in such calendar year and 50% of proved undeveloped reserves projected to be producing during such calendar year and, (y) in the case of contractual arrangements, do not exceed 75% of the Company's and its Subsidiaries' pro rata share of minimum contracted volumes of gas to be collected and/or processed in such calendar year. "Hedging Transactions" shall mean, with respect to the Company and its Subsidiaries, any commodity basis swap, forward commodity transaction, commodity swap, commodity option, commodity index swap, commodity cap transaction, commodity floor transaction, commodity collar transaction, any other similar transaction that relates to commodities (including any option with respect to any of the foregoing transactions) or any combination of the foregoing transactions. The Company will deliver to the holder of each Note a statement detailing its hedge position in a form satisfactory to the Required Holders at the same time it delivers the financial statements contemplated by paragraphs 5A(i) and 5A(ii).

PARAGRAPH 7. EVENTS OF DEFAULT.

        7A.    Acceleration.    If any of the following events shall occur for any reason whatsoever and be continuing (and whether such occurrence shall be voluntary or involuntary or come about or be effected by operation of law or otherwise):

        (i)    the Company defaults in the payment of any principal of or Yield-Maintenance Amount payable with respect to any Note when the same shall become due, either by the terms thereof or otherwise as herein provided; or

        (ii)  the Company defaults in the payment of any interest or Credit Fee on any Note for more than 10 Business Days after the date due; or

        (iii)  the Company or any Subsidiary defaults (whether as primary obligor or as guarantor or other surety) in any payment of principal of or interest on any other obligation for money borrowed (or any Capitalized Lease Obligation, any obligation under a conditional sale or other title retention agreement, any obligation issued or assumed as full or partial payment for property whether or not secured by a purchase money mortgage or any obligation under notes payable or drafts accepted representing extensions of credit) beyond any period of grace provided with respect thereto, or the Company or any Subsidiary fails to perform or observe any other agreement, term or condition contained in any agreement under which any such obligation is created (or if any other event thereunder or under any such agreement shall occur and be continuing) and the effect of such failure or other event is to cause, or to permit the holder or holders of such obligation (or a trustee on behalf of such holder or holders) to cause, such obligation to become due (or to be repurchased by the Company or any Subsidiary) prior to any stated maturity, provided that the aggregate amount of all obligations as to which such a payment default shall occur and be continuing or such a failure or other event causing or permitting acceleration (or resale to the Company or any Subsidiary) shall occur and be continuing exceeds $5,000,000; or

        (iv)  any representation or warranty made by the Company herein or in the Company Pledge Agreement, by any Guarantor in a Guaranty or a Pledge Agreement or by the Company, any Guarantor or any of their respective officers in any writing furnished in connection with or pursuant to this Agreement shall be false in any material respect on the date as of which made; or

        (v)  the Company fails to perform or observe any term, covenant or agreement contained in paragraph 6; or

        (vi)  the Company fails to perform or observe any other agreement, covenant, term or condition contained herein and such failure shall not be remedied within 30 days after the chief executive officer, President, chief financial officer, Treasurer or the Executive Vice President—General Counsel of the Company obtains actual knowledge thereof; or

        (vii) the Company or any Subsidiary makes an assignment for the benefit of creditors or is generally not paying its debts as such debts become due; or

        (viii)  any decree or order for relief in respect of the Company or any Subsidiary is entered under any bankruptcy, reorganization, compromise, arrangement, insolvency, readjustment of debt, dissolution or liquidation or similar law, whether now or hereafter in effect (herein called the "Bankruptcy Law"), of any jurisdiction; or

        (ix)  the Company or any Subsidiary petitions or applies to any tribunal for, or consents to, the appointment of, or taking possession by, a trustee, receiver, custodian, liquidator or similar official of the Company or any Subsidiary, or of any substantial part of the assets of the Company or any Subsidiary, or commences a voluntary case under the Bankruptcy Law of the United States or any proceedings (other than proceedings for the voluntary liquidation and dissolution of a Subsidiary) relating to the Company or any Subsidiary under the Bankruptcy Law of any other jurisdiction; or

        (x)  any such petition or application is filed, or any such proceedings are commenced, against the Company or any Subsidiary and the Company or such Subsidiary by any act indicates its approval thereof, consent thereto or acquiescence therein, or an order, judgment or decree is entered appointing any such trustee, receiver, custodian, liquidator or similar official, or approving the petition in any such proceedings, and such order, judgment or decree remains unstayed and in effect for more than 30 days; or

        (xi)  any order, judgment or decree is entered in any proceedings against the Company decreeing the dissolution of the Company and such order, judgment or decree remains unstayed and in effect for more than 60 days; or

        (xii) any order, judgment or decree is entered in any proceedings against the Company or any Subsidiary decreeing a split-up of the Company or such Subsidiary which requires the divestiture of assets representing a substantial part, or the divestiture of the stock of a Subsidiary whose assets represent a substantial part, of the consolidated assets of the Company and its Subsidiaries (determined in accordance with generally accepted accounting principles) or which requires the divestiture of assets, or stock of a Subsidiary, which shall have contributed a substantial part of the Consolidated Net Earnings of the Company and its Subsidiaries (determined in accordance with generally accepted accounting principles) for any of the three fiscal years then most recently ended, and such order, judgment or decree remains unstayed and in effect for more than 60 days; or

        (xiii)  any judgment or order, or series of judgments or orders, for the payment of money in an amount in excess of $5,000,000 is rendered against the Company or any Subsidiary and either (i) enforcement proceedings have been commenced by any creditor upon such judgment or order or (ii) within 30 days after entry thereof, such judgment is not discharged or execution thereof stayed pending appeal, or within 30 days after the expiration of any such stay, such judgment is not discharged; or

        (xiv)   (a) the Company or any other Person who is a member of the Company's "control group" (as such term is defined under ERISA) fails to make all or any portion of a required installment payment under 29 U.S.C. §1082(e) with respect to any Plan, (b) the aggregate unpaid balance of such installment together with the unpaid balance of all prior installments and other payments due under 29 U.S.C. §1082 (including any accrued interest on such amounts) exceeds $1,000,000, and (c) such amounts remain unpaid for more than 30 days after the due date of the installment referred to in clause (a); or

        (xv) the Company or any of its Affiliates as employer under a Multiemployer Plan shall have made a complete or partial withdrawal from such Multiemployer Plan and the plan sponsor of such Multiemployer Plan shall have notified such withdrawing employer that such employer has incurred a withdrawal liability in an annual amount exceeding $1,000,000; or

        (xvi)   any Guaranty, for any reason, ceases to be in full force and effect or is declared null and void, or the validity or enforceability thereof is contested or the Guarantor denies that it has any further liability under the Guaranty, or the Guarantor shall default in the performance or observance of any of its obligations under the Guaranty, and such default shall not have been remedied within 30 days; or

        (xvii)  any Pledge Agreement, for any reason other than as specified therein, ceases to be in full force and effect or is declared null and void or shall cease to create a valid and perfected first priority security interest in any of the collateral purported to be covered thereby, or the validity or enforceability thereof is contested or the Company denies that it has any further liability under any Pledge Agreement, or the Company shall default in the performance or observance of any of its obligations under the Pledge Agreement, and such default shall not have been remedied within 30 days;

then (a) if such event is an Event of Default specified in clause (viii), (ix) or (x) of this paragraph 7A with respect to the Company, any Restricted Subsidiary that is a Significant Subsidiary or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all of the Notes at the time outstanding shall automatically become immediately due and payable at par together with interest and Credit Fee accrued thereon, without presentment, demand, protest or notice of any kind (including, without limitation, notice of intent to accelerate and notice of acceleration of maturity), all of which are hereby waived by the Company, (b) if such event is an Event of Default specified in clause (i) or (ii) of this paragraph 7A, any Significant Holder that holds a Note other than the Company or any of its Subsidiaries or Affiliates) as to which such an Event of Default shall have occurred may at its option during the continuance of such Event of Default, by notice in writing to the Company, declare such Note to be, and such Note shall thereupon be and become, immediately due and payable together with interest and Credit Fee accrued thereon and together with the Yield-Maintenance Amount, if any, with respect to each such Note, without presentment, demand, protest or notice of any kind (including, without limitation, notice of intent to accelerate), all of which are hereby waived by the Company and (c) if such event is any other Event of Default, the Required Holder(s) may at its or their option during the continuance of such Event of Default, by notice in writing to the Company, declare all of the Notes to be, and all of the Notes shall thereupon be and become, immediately due and payable together with interest and Credit Fee accrued thereon and together with the Yield-Maintenance Amount, if any, with respect to each Note, without presentment, demand, protest or notice of any kind (including, without limitation, notice of intent to accelerate), all of which are hereby waived by the Company.

        The Company acknowledges and the parties hereto agree, that the holder of each Note has the right to maintain its investment in the Notes free from repayment by the Company (except as herein specifically provided for) and the provisions for payment of the Yield-Maintenance Amount by the Company in the event that the Notes are prepaid or are accelerated as a result of an Event of Default, are intended to provide compensation for the deprivation of such right under such circumstances.

        7B.    Rescission of Acceleration.    At any time after any or all of the Notes are declared immediately due and payable and have not been paid in full, the Required Holder(s) may, by notice in writing to the Company, rescind and annul such declaration and its consequences if (i) the Company has paid all overdue interest and Credit Fees on the Notes, the principal of and Yield-Maintenance Amount, if any, payable with respect to any Notes which have become due otherwise than by reason of such declaration, and interest (at the rate specified in the Notes) and Credit Fees on such overdue interest and Credit Fees and overdue principal and Yield-Maintenance Amount at the rate specified in the Notes, (ii) all Events of Default and Defaults, other than non-payment of amounts which have become due solely by reason of such declaration have been cured or waived pursuant to paragraph 11C, and (iii) no judgment or decree has been entered for the payment of any monies due pursuant to the Notes or this Agreement. No such rescission or annulment shall extend to or affect any subsequent Event of Default or Default or impair any right arising therefrom.

        7C.    Notice of Acceleration or Rescission.    Whenever any Note shall be declared immediately due and payable pursuant to paragraph 7A or any such declaration shall be rescinded and annulled pursuant to paragraph 7B, the Company shall forthwith give written notice thereof to the holder of each Note at the time outstanding.

        7D.    Other Remedies.    If any Event of Default or Default shall occur and be continuing, the holder of any Note may proceed to protect and enforce its rights under this Agreement and such Note by exercising such remedies as are available to such holder in respect thereof under applicable law, either by suit in equity or by action at law, or both, whether for specific performance of any covenant or other agreement contained in this Agreement or in aid of the exercise of any power granted in this Agreement. No remedy conferred in this Agreement upon the holder of any Note is intended to be exclusive of any other remedy, and each and every such remedy shall be cumulative and shall be in addition to every other remedy conferred herein or now or hereafter existing at law or in equity or by statute or otherwise.

PARAGRAPH 8. REPRESENTATIONS, COVENANTS AND WARRANTIES.

        8.    Representations, Covenants and Warranties.    The Company represents, covenants and warrants as follows:

        8A.    Organization.    The Company is a corporation duly organized and existing in good standing under the laws of the State of Delaware, each Subsidiary is duly organized and existing in good standing under the laws of the jurisdiction in which it is incorporated, and the Company has and each Subsidiary has the corporate power to own its respective property and to carry on its respective business as now being conducted. The execution, delivery and performance by the Company of this Agreement and the Notes are within the Company's corporate powers and have been duly authorized by all necessary corporate action.

        8B.    Financial Statements.    The Company has furnished each Purchaser of any Accepted Notes with the following financial statements, identified by a principal financial officer of the Company: (i) a consolidated balance sheet of the Company and its Subsidiaries as at December 31 in each of the three fiscal years of the Company most recently completed prior to the date as of which this representation is made or repeated to such Purchaser (other than fiscal years completed within 90 days prior to such date for which audited financial statements have not been released) and a consolidated statement of income and statement of cash flows of the Company and its Subsidiaries for each such year, all certified by the Company's then-current nationally recognized independent auditing firm; and (ii) consolidated balance sheets of the Company and its Subsidiaries as at the end of the quarterly period (if any) most recently completed prior to such date and after the end of such fiscal year (other than quarterly periods completed within 45 days prior to such date for which financial statements have not been released) and the comparable quarterly period in the preceding fiscal year and consolidated statements of income and statements of cash flows for the periods from the beginning of the fiscal years in which such quarterly periods are included to the end of such quarterly periods, prepared by the Company. Such financial statements (including any related schedules and/or notes) are true and correct in all material respects (subject, as to interim statements, to changes resulting from audits and year-end adjustments), have been prepared in accordance with generally accepted accounting principles consistently followed (except as set forth in the notes thereto if consistent with generally accepted accounting principles and generally accepted auditing standards) throughout the periods involved and show all liabilities, direct and contingent, of the Company and its Subsidiaries required to be shown in accordance with such principles. The balance sheets fairly present the condition of the Company and its Subsidiaries as at the dates thereof, and the statements of income and statements of cash flows fairly present the results of the operations of the Company and its Subsidiaries for the periods indicated. There has been no material adverse change in the business, condition or operations (financial or otherwise) of the Company and its Subsidiaries taken as a whole since the end of the most recent fiscal year for which such audited financial statements have been furnished.

        8C.    Actions Pending.    There is no action, suit, investigation or proceeding pending or, to the knowledge of the Company, threatened against the Company or any of its Subsidiaries, or any properties or rights of the Company or any of its Subsidiaries, by or before any court, arbitrator or administrative or governmental body which might result in any material adverse change in the business, condition or operations of the Company and its Subsidiaries taken as a whole. There is no action, suit, investigation or proceeding pending or threatened against the Company or any of its Subsidiaries which purports to affect the validity or enforceability of this Agreement or any Note.

        8D.    Outstanding Debt.    Neither the Company nor any of its Subsidiaries has outstanding any Debt except as permitted by paragraph 6C(2). There exists no default under the provisions of any instrument evidencing such Debt or of any agreement relating thereto.

        8E.    Environmental Compliance.    The Company and its Subsidiaries and all of their respective properties and facilities have complied at all times and in all respects with all federal, state, local and regional statutes, laws, ordinances and judicial and administrative orders, judgments, rulings and regulations relating to protection of the environment except, in any such case, where failure to comply would not result in a material adverse effect on the business, condition (financial or otherwise) or operations of the Company and its Subsidiaries taken as a whole.

        8F.    Taxes.    The Company has and each of its Subsidiaries has filed all Federal, State and other income tax returns which, to the best knowledge of the officers of the Company and its Subsidiaries, are required to be filed, and each has paid all taxes as shown on such returns and on all assessments received by it to the extent that such taxes have become due, except such taxes as are being contested in good faith by appropriate proceedings and for which adequate reserves have been established in accordance with generally accepted accounting principles.

        8G.    Conflicting Agreements and Other Matters.    Neither the Company nor any of its Subsidiaries is a party to any contract or agreement or subject to any charter or other corporate restriction which materially and adversely affects its business, property or assets, or financial condition. Neither the execution nor delivery of this Agreement or the Notes, nor the offering, issuance and sale of the Notes, nor fulfillment of nor compliance with the terms and provisions hereof and of the Notes will conflict with, or result in a breach of the terms, conditions or provisions of, or constitute a default under, or result in any violation of, or result in the creation of any Lien upon any of the properties or assets of the Company or any of its Subsidiaries pursuant to, the charter or by-laws of the Company or any of its Subsidiaries, any award of any arbitrator or any agreement (including any agreement with stockholders), instrument, order, judgment, decree, statute, law, rule or regulation to which the Company or any of its Subsidiaries is subject. Neither the Company nor any of its Subsidiaries is a party to, or otherwise subject to any provision contained in, any instrument evidencing indebtedness of the Company or such Subsidiary, any agreement relating thereto or any other contract or agreement (including its charter) which limits the amount of, or otherwise imposes restrictions on the incurring of, Debt of the Company of the type to be evidenced by the Notes except as set forth in the agreements listed in Exhibit E attached hereto.

        8H.    Offering of Notes.    Neither the Company nor any agent acting on its behalf has, directly or indirectly, offered the Notes or any similar security of the Company for sale to, or solicited any offers to buy the Notes or any similar security of the Company from, or otherwise approached or negotiated with respect thereto with, any Person other than institutional investors, and neither the Company nor any agent acting on its behalf has taken or will take any action which would subject the issuance or sale of the Notes to the provisions of Section 5 of the Securities Act or to the provisions of any securities or Blue Sky law of any applicable jurisdiction.

        8I.    Regulation U, etc.    The proceeds of the sale of the Notes will be used to refinance existing indebtedness or for general corporate purposes. None of the proceeds of the sale of any Notes will be used, directly or indirectly, for the purpose, whether immediate, incidental or ultimate, of purchasing or carrying any "margin stock" as defined in Regulation U (12 CFR Part 221) of the Board of Governors of the Federal Reserve System (herein called "margin stock") or for the purpose of maintaining, reducing or retiring any indebtedness which was originally incurred to purchase or carry any stock that is then currently a margin stock or for any other purpose which might constitute the purchase of such Notes a "purpose credit" within the meaning of such Regulation U, unless the Company shall have delivered to the Purchaser which is purchasing such Notes, on the Closing Day for such Notes, an opinion of counsel satisfactory to such Purchaser stating that the purchase of such Notes does not constitute a violation of such Regulation U. After applying the proceeds of the sale of the Notes, not more than 25% of the value of the assets subject to the terms of paragraph 5C, 6C(1), 6C(4) or 6C(5) will be "margin stock." Neither the Company nor any agent acting on its behalf has taken or will take any action which might cause this Agreement or the Notes to violate Regulation U, Regulation T or any other regulation of the Board of Governors of the Federal Reserve System or to violate the Exchange Act, in each case as in effect now or as the same may hereafter be in effect.

        8J.    ERISA.    No accumulated funding deficiency (as defined in Section 302 of ERISA and Section 412 of the Code), whether or not waived, exists with respect to any Plan (other than a Multiemployer Plan). No liability to the PBGC has been or is expected by the Company to be incurred with respect to any Plan (other than a Multiemployer Plan) by the Company or any of its Subsidiaries which is or would be materially adverse to the Company and its Subsidiaries taken as a whole. Neither the Company nor any of its Subsidiaries has incurred or presently expects to incur any withdrawal liability under Title IV of ERISA with respect to any Multiemployer Plan which is or would be materially adverse to the Company and its Subsidiaries taken as a whole. No Plan providing welfare benefits to retired former employees of the Company or any of its Subsidiaries has been established or is maintained for which the present value of future benefits payable, in excess of irrevocably designated funds for such purpose, is materially adverse to the financial condition of the Company and its Subsidiaries taken as a whole. Either PTE 84-14 or PTE 90-1 applies to the purchase of the Notes to be purchased by the Purchasers, and the execution and delivery of this Agreement and the issuance and sale of the Notes will not involve any transaction which is subject to the prohibitions of Section 406 of ERISA or in connection with which a penalty could be imposed under Section 502(i) of ERISA or a tax could be imposed pursuant to Section 4975 of the Code. The representation by the Company in the next preceding sentence is made in reliance upon and subject to the accuracy of your representation in paragraph 9B.

        8K.    Governmental Consent.    Neither the nature of the Company or of any Subsidiary, nor any of their respective businesses or properties, nor any relationship between the Company or any Subsidiary and any other Person, nor any circumstance in connection with the offering, issuance, sale or delivery of the Notes is such as to require any authorization, consent, approval, exemption or other action by or notice to or filing with any court or administrative or governmental or regulatory body (other than routine filings after the Closing Day for any Notes with the Securities and Exchange Commission and/or state Blue Sky authorities) in connection with the execution and delivery of this Agreement, the offering, issuance, sale or delivery of the Notes or fulfillment of or compliance with the terms and provisions hereof or of the Notes.

        8L.    Title to Properties.    The Company has and each of its Subsidiaries has good and defensible title to its respective real properties (other than properties which it leases) and good title to all of its other respective properties and assets, including the properties and assets reflected in the most recent audited balance sheet referred to in paragraph 8B (other than properties and assets disposed of in the ordinary course of business), subject to no Lien of any kind except Liens permitted by paragraph 6C(1) except that (i) with respect to easements and rights of way associated with the Company's gas gathering systems: (a) the Company has such title as is customary and appropriate in accordance with applicable industry standards and (b) the costs of curing defects in such title, if any, would not exceed $10,000,000 in the aggregate and (ii) no representation or warranty is made with respect to any gas or mineral property or interest to which no proved oil or gas reserves are properly attributed. All leases necessary in any material respect for the conduct of the respective businesses of the Company and its Subsidiaries are valid and subsisting and are in full force and effect.

        8M.    Hostile Tender Offers.    None of the proceeds of the sale of any Notes will be used to finance a Hostile Tender Offer.

        8N.    Disclosure.    Neither this Agreement nor the Offering Materials nor any other document, certificate or statement furnished to any Purchaser by or on behalf of the Company in connection herewith contains any untrue statement of a material fact or omits to state a material fact necessary in order to make the statements contained herein and therein not misleading. There is no fact peculiar to the Company or any of its Subsidiaries which materially adversely affects or in the future may (so far as the Company can now foresee) materially adversely affect the business, property or assets, or financial condition of the Company and its Subsidiaries taken as a whole and which has not been set forth in this Agreement or with respect to any Purchaser, in the Offering Materials furnished to such Purchaser by or on behalf of the Company prior to the Request for Purchase of the Accepted Notes to be purchased by such Purchaser. The financial projections contained in the Offering Materials are reasonable based on the assumptions stated therein and the best information available to the officers of the Company.

        8O.    Delivery of NCNB Agreement.    The Company has delivered to each Purchaser prior to the date hereof a true, correct and complete copy of the NCNB Agreement, including all amendments and waivers of any provision thereof.

        8P.    Public Utility Holding Company Act; Federal Power Act.    Neither the Company nor any Subsidiary is a "holding company" or a "subsidiary company" of a "holding company" or a "public utility company" as such terms are defined in the Public Utility Holding Company Act of 1935, as amended, or, except for Western Power Services, Inc., a "public utility" as such term is defined in the Federal Power Act, as amended.

        8Q.    Existing Guaranties.    No Subsidiary, and no entity that would constitute a Subsidiary but for its being organized under the laws of the jurisdiction outside the United States of America, has executed and delivered a guaranty in favor of the agent or lenders parties to the NCNB Agreement except Subsidiaries that have executed and delivered Guaranties to the holders of the Notes.

        8R.    No Default.    Immediately prior to the Effective Date there existed no Default or Event of Default as such terms are defined in the Existing Agreement.

PARAGRAPH 9. REPRESENTATIONS AND COVENANTS OF THE PURCHASERS.

        9A.    Nature of Purchase.    Each Purchaser represents that it is not acquiring the Notes to be purchased by it hereunder with a view to or for sale in connection with any distribution thereof within the meaning of the Securities Act, provided that the disposition of such Purchaser's property shall at all times be and remain within its control.

        9B.    Source of Funds.    Each Purchaser represents that at least one of the following statements concerning each source of funds to be used by it to purchase any Notes (respectively, the "Source") is accurate as of the Closing Day with respect to such Notes:

        (i)    the Source is an "insurance company general account" (as the term is defined in the United States Department of Labor's Prohibited Transaction Exemption ("PTE") 95-60) in respect of which the reserves and liabilities (as defined by the annual statement for life insurance companies approved by the National Association of Insurance Commissioners (the "NAIC Annual Statement")) for the general account contract(s) held by or on behalf of any employee benefit plan together with the amount of the reserves and liabilities for the general account contract(s) held by or on behalf of any other employee benefit plans maintained by the same employer (or affiliate thereof as defined in PTE 95-60) or by the same employee organization in the general account do not exceed 10% of the total reserves and liabilities of the general account (exclusive of separate account liabilities) plus surplus as set forth in the NAIC Annual Statement filed with such Purchaser's state of domicile; or

        (ii)  the Source is a separate account that is maintained solely in connection with such Purchaser's fixed contractual obligations under which the amounts payable, or credited, to any employee benefit plan (or its related trust) that has any interest in such separate account (or to any participant or beneficiary of such plan (including any annuitant)) are not affected in any manner by the investment performance of the separate account; or

        (iii)  the Source is either (a) an insurance company pooled separate account, within the meaning of PTE 90-1 or (b) a bank collective investment fund, within the meaning of the PTE 91-38 and, except as disclosed by such Purchaser to the Company in writing pursuant to this clause (iii), no employee benefit plan or group of plans maintained by the same employer or employee organization beneficially owns more than 10% of all assets allocated to such pooled separate account or collective investment fund; or

        (iv)  the Source constitutes assets of an "investment fund" (within the meaning of Part V of PTE 84-14 (the "QPAM Exemption")) managed by a "qualified professional asset manager" or "QPAM" (within the meaning of Part V of the QPAM Exemption), no employee benefit plan's assets that are included in such investment fund, when combined with the assets of all other employee benefit plans established or maintained by the same employer or by an affiliate (within the meaning of Section V(c)(1) of the QPAM Exemption) of such employer or by the same employee organization and managed by such QPAM, exceed 20% of the total client assets managed by such QPAM, the conditions of Part I(c) and (g) of the QPAM Exemption are satisfied, neither the QPAM nor a person controlling or controlled by the QPAM (applying the definition of "control" in Section V(e) of the QPAM Exemption) owns a 5% or more interest in the Company and (a) the identity of such QPAM and (b) the names of all employee benefit plans whose assets are included in such investment fund have been disclosed to the Company in writing pursuant to this clause (iv); or

        (v)  the Source constitutes assets of a "plan(s)" (within the meaning of Section IV of PTE 96-23 (the "INHAM Exemption")) managed by an "in-house asset manager" or "INHAM" (within the meaning of Part IV of the INHAM exemption), the conditions of Part I(a), (g) and (h) of the INHAM Exemption are satisfied, neither the INHAM nor a person controlling or controlled by the INHAM (applying the definition of "control" in Section IV(h) of the INHAM Exemption) owns a 5% or more interest in the Company and (a) the identity of such INHAM and (b) the name(s) of the employee benefit plan(s) whose assets constitute the Source have been disclosed to the Company in writing pursuant to this clause (v); or

        (vi)  the Source is a governmental plan; or

        (vii) the Source is one or more employee benefit plans, or a separate account or trust fund comprised of one or more employee benefit plans, each of which has been identified to the Company in writing pursuant to this clause (vii); or

        (viii)  the Source does not include assets of any employee benefit plan, other than a plan exempt from the coverage of ERISA.

As used in this paragraph 9B, the terms "employee benefit plan," "governmental plan," and "separate account" shall have the respective meanings assigned to such terms in Section 3 of ERISA.

        9C.    Covenants.

        9C(1).    Collateral Agent.    Each holder of Notes, by its acceptance of a Note, hereby irrevocably appoints and authorizes Prudential to act as Collateral Agent under each Pledge Agreement with such powers and discretions as are specifically delegated to Prudential, as Secured Party, by the terms of each Pledge Agreement. Prudential hereby accepts such appointment.

        9C(2).    Pledge Agreements.    Each holder of Notes, by its acceptance of a Note, agrees to all of the terms, covenants, agreements and indemnification included in each Pledge Agreement that apply to a "Noteholder" (as defined in each Pledge Agreement) as if such holder had executed such Pledge Agreement.

        9C(3).    Intercreditor Agreement.    Each holder of Notes, by its acceptance of a Note, hereby irrevocably appoints and authorizes Prudential to act on behalf of such holder under the Intercreditor Agreement to bind such holder to the terms thereof. Prudential hereby accepts such appointment.

PARAGRAPH 10. DEFINITIONS.

        10.    Definitions.    For the purpose of this Agreement, the terms defined in the introductory sentence and in paragraphs 1 and 2 shall have the respective meanings specified therein, and the following terms shall have the meanings specified with respect thereto below (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

        10A.    Yield-Maintenance Terms

        "Called Principal" shall mean, with respect to any Note, the principal of such Note that is to be prepaid pursuant to paragraph 4B or is declared to be immediately due and payable pursuant to paragraph 7A, as the context requires.

        "Discounted Value" shall mean, with respect to the Called Principal of any Note, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal, in accordance with accepted financial practice and at a discount factor (applied on a quarterly basis) equal to the Reinvestment Yield with respect to such Called Principal.

        "Reinvestment Yield" shall mean, with respect to the Called Principal of any Note, the yield to maturity implied by (a) the yields reported, as of 10:00 A.M. (New York City local time) on the Business Day next preceding the Settlement Date with respect to such Called Principal, on the Treasury Yield Monitor Page for actively traded U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date, or if such yields shall not be reported as of such time or the yields reported as of such time shall not be ascertainable, (b) the Treasury Constant Maturity Series yields reported, for the latest day for which such yields shall have been so reported as of the Business Day next preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (519) (or any comparable successor publication) for actively traded U.S. Treasury securities having a constant maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. Such implied yield shall be determined, (i) if necessary, by (x) converting U.S. Treasury bill quotations to bond-equivalent yields in accordance with accepted financial practice and (y) interpolating linearly between yields reported for various maturities and, (ii) if interest on such Notes is paid quarterly, by converting all such implied yields to a quarterly payment basis in accordance with accepted financial practice. The Reinvestment Yield shall be rounded to that number of decimal places as appears in the coupon of the applicable Note.

        "Remaining Average Life" shall mean, with respect to the Called Principal of any Note, the number of years (calculated to the nearest one-twelfth year) obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) each Remaining Scheduled Payment of such Called Principal (but not of interest thereon) by (b) the number of years (calculated to the nearest one-twelfth year) which will elapse between the Settlement Date with respect to such Called Principal and the scheduled due date of such Remaining Scheduled Payment.

        "Remaining Scheduled Payments" shall mean, with respect to the Called Principal of any Note, all payments of such Called Principal and interest thereon that would be due on or after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its scheduled due date.

        "Settlement Date" shall mean, with respect to the Called Principal of any Note, the date on which such Called Principal is to be prepaid pursuant to paragraph 4A or is declared to be immediately due and payable pursuant to paragraph 7A, as the context requires.

        "Yield-Maintenance Amount" shall mean, with respect to any Note, an amount equal to the excess, if any, of the Discounted Value of the Called Principal of such Note over the sum of (i) such Called Principal plus (ii) interest accrued thereon as of (including interest due on) the Settlement Date with respect to such Called Principal. The Yield-Maintenance Amount shall in no event be less than zero.

        10B.    Other Terms

        "Acceptance" shall have the meaning specified in paragraph 2F.

        "Acceptance Day" shall have the meaning specified in paragraph 2F.

        "Acceptance Window" shall have the meaning specified in paragraph 2F.

        "Accepted Note" shall have the meaning specified in paragraph 2F.

        "Affiliate" shall mean any Person directly or indirectly controlling, controlled by, or under direct or indirect common control with, the Company, except a Subsidiary. A Person shall be deemed to control a corporation if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such corporation, whether through the ownership of voting securities, by contract or otherwise.

        "Agreement" shall have the meaning specified in paragraph 11C.

        "Authorized Officer" shall mean (i) in the case of the Company, its Chief Executive Officer, its Chief Financial Officer, its President or the Executive Vice President-General Counsel of the Company or its Vice President-Finance or Treasurer and (ii) in the case of Prudential, any officer of Prudential designated as its "Authorized Officer" in the Purchaser Schedule or any officer of Prudential designated as its "Authorized Officer" for the purpose of this Agreement in a certificate executed by one of its Authorized Officers. Any action taken under this Agreement on behalf of the Company by any individual who on or after the date of this Agreement shall have been an Authorized Officer of the Company and whom Prudential in good faith believes to be an Authorized Officer of the Company at the time of such action shall be binding on the Company even though such individual shall have ceased to be an Authorized Officer of the Company, and any action taken under this Agreement on behalf of Prudential by any individual who on or after the date of this Agreement shall have been an Authorized Officer of Prudential, and whom the Company in good faith believes to be an Authorized Officer of Prudential at the time of such action shall be binding on Prudential even though such individual shall have ceased to be an Authorized Officer of Prudential.

        "Available Facility Amount" shall have the meaning specified in paragraph 2A.

        "Bank Guaranty" shall mean each guaranty of a Guarantor in favor of the banks parties to the NCNB Agreement for which a similar guaranty shall have been issued to each holder of Notes.

        "Bankruptcy Law" shall have the meaning specified in clause (viii) of paragraph 7A.

        "Business Day" shall mean any day other than a Saturday, a Sunday or a day on which commercial banks in New York City are required or authorized to be closed.

        "Cancellation Date" shall have the meaning specified in paragraph 2I(3).

        "Cancellation Fee" shall have the meaning specified in paragraph 2I(3).

        "Capitalized Lease Obligation" shall mean any rental obligation which, under generally accepted accounting principles, is or will be required to be capitalized on the books of the Company or any Subsidiary, taken at the amount thereof accounted for as indebtedness (net of interest expenses) in accordance with such principles.

        "Closing Day" for any Accepted Note shall mean the Business Day specified for the closing of the purchase and sale of such Note in the Request for Purchase of such Note, provided that (i) if the Acceptance Day for such Accepted Note is less than five Business Days after the Company shall have made such Request for Purchase and the Company and the Purchaser which is obligated to purchase such Note agree on an earlier Business Day for such closing, the "Closing Day" for such Accepted Note shall be such earlier Business Day, and (ii) if the closing of the purchase and sale of such Accepted Note is rescheduled pursuant to paragraph 2H(3), the Closing Day for such Accepted Note, for all purposes of this Agreement except paragraph 2I(3), shall mean the Rescheduled Closing Day with respect to such Closing.

        "Code" shall mean the Internal Revenue Code of 1986, as amended.

        "Collateral" shall mean all of the "Collateral" as defined in each Pledge Agreement.

        "Collateral Agent" shall mean Prudential and any successor collateral agent under the Pledge Agreements.

        "Company Pledge Agreement" shall mean the Pledge Agreement, dated as of April 29, 1999, by the Company in favor of Prudential, as collateral agent (Prudential being the successor to PICA, the original collateral agent) for the holders of the Notes, as amended by Amendment No. 1 to Pledge Agreement dated as of the Effective Date and as the provisions thereof may be from time to time amended or waived in compliance with the terms thereof.

        "Confidential Information" shall mean any material non-public information regarding the Company and its Subsidiaries that is provided to any holder of any Note, any Person who purchases a participation in a Note and any offeree of a Note or participation therein pursuant to this Agreement other than information (i) which was publicly known or otherwise known to such holder, such Person or such offeree at the time of disclosure, (ii) which subsequently becomes publicly known through no act or omission of such holder, such Person or such offeree or (iii) which otherwise becomes known to such holder, such Person or such offeree, other than through disclosure by the Company or any Subsidiary.

        "Confirmation of Acceptance" shall have the meaning specified in paragraph 2F.

        "Consolidated Debt" shall mean the consolidated Debt of the Company and its Subsidiaries, determined in accordance with generally accepted accounting principles.

        "Consolidated Net Earnings" shall mean consolidated gross revenues of the Company and its Subsidiaries excluding gains resulting from the sale, conversion or other disposition of capital assets (including capital stock of Subsidiaries and other assets not constituting current assets) and other non-cash gains, less all operating and non-operating expenses of the Company and its Subsidiaries (other than losses resulting from the sale, conversion or other disposition of capital assets, including capital stock of Subsidiaries and other assets not constituting current assets and other non-cash losses) and all charges of a proper character (including current and deferred taxes on income, provision for taxes on unremitted foreign earnings that are included in gross revenues, and current additions to reserves), but not including in gross revenues any gains resulting from the write-up of assets, any equity of the Company or any Subsidiary in the unremitted earnings of any Person that is not a Subsidiary, any earnings of any Person acquired by the Company or any Subsidiary through purchase, merger or consolidation or otherwise for any period prior to the time of acquisition, or any deferred credit representing the excess of equity in any Subsidiary at the date of acquisition over the cost of the investment in such Subsidiary, all determined in accordance with generally accepted accounting principles.

        "Consolidated Net Earnings Available For Restricted Payments" shall mean an amount equal to (1) the sum of $50,000,000 plus (2) 50% (or minus 100% in case of a deficit) of Consolidated Net Earnings for the period commencing on July 1, 1995 and terminating at the end of the last fiscal quarter preceding the date of any proposed Restricted Payment (taken as one accounting period), less (3) the sum of all Restricted Payments made or declared after July 1, 1995, plus (4) the aggregate amount received by the Company after July 1, 1995, as the net cash proceeds of the sale of any shares of its stock. There shall not be included in Restricted Payments or in any computation of Consolidated Net Earnings Available for Restricted Payments (x) dividends paid, or distributions made, in stock of the Company or (y) exchanges of stock of one or more classes of the Company, except to the extent that cash or other value is involved in such exchange. The term "stock" as used in this definition and in the definition of "Restricted Payments" shall include warrants or options to purchase stock.

        "Consolidated Net Tangible Assets" shall mean the consolidated assets of the Company and its Subsidiaries, less, without duplication, (i) Consolidated Current Liabilities minus Excess Working Capital Deficit, (ii) asset, liability, contingency and other reserves of the Company and its Subsidiaries, including reserves for depreciation and for deferred income taxes, (iii) all other liabilities of the Company and its Subsidiaries, except liabilities for Funded Debt of the types described in clauses (i), (ii) and (iii) of the definition of Debt, and (iv) treasury stock, unamortized debt discount and expense, goodwill, trademarks, brand names, patents, organizational expenses and any other intangible assets of the Company and its Subsidiaries, and any write-up of the value of any assets after June 30, 1991, all as determined in accordance with generally accepted accounting principles; provided, however, that the term "Consolidated Net Tangible Assets" shall include the book value of long-term gas contracts with producers that the Company assumes in connection with acquisitions and that are reflected on the books of the Company as assets.

        "Consolidated Senior Debt" shall mean Consolidated Debt less all Subordinated Debt.

        "Consolidated Tangible Net Worth" shall mean consolidated stockholders' equity of the Company and its Subsidiaries, less goodwill, trademarks, brand names, patents, organizational expenses and any other intangible assets of the Company and its Subsidiaries, all as determined in accordance with generally accepted accounting principles; provided, however, that the term "Consolidated Tangible Net Worth" shall include the book value of long-term gas contracts with producers that the Company assumes in connection with acquisitions and that are reflected on the books of the Company as assets.

        "Counterparty" shall mean (i) any Person described in Schedule 6C(8), (ii) any Person that is not an Affiliate of the Company and that has senior debt securities rated at least A by S & P or Moody's or whose obligations in respect of the agreements described in the final proviso to paragraph 6C(8) or in the definition of Long Hedge Future or Short Hedge Future, as the case may be, are fully guaranteed by an affiliate of such Person whose senior debt securities are so rated, and (iii) any other Person that is not an Affiliate of the Company and with whom the Company has agreements of the nature described in the final proviso to paragraph 6C(8) or in the definition of Long Hedge Future or Short Hedge Future, so long as (a) the aggregate amount of all such agreements with such Person outstanding at any time shall not exceed $1,000,000 and (b) the Company has such agreements outstanding with no more than nine other such Persons at any time.

        "Credit Fee" shall have the meaning specified in paragraph 5O.

        "Debt" shall mean, without duplication:

        (i)    any obligation that, under generally accepted accounting principles, is shown on the balance sheet as a liability (including, without limitation, any obligation for borrowed money, any notes payable and drafts accepted representing extensions of credit, whether or not representing obligations for borrowed money, and Capitalized Lease Obligations but excluding accounts payable and accrued expenses in the ordinary course of business, reserves for deferred income taxes and other reserves to the extent that such reserves do not constitute an obligation),

        (ii)  any obligation secured by a Lien on, or payable out of the proceeds of production from, property, whether or not the obligation secured thereby shall have been assumed by the owner of such property,

        (iii)  liabilities in respect of unfunded vested benefits under Plans and liabilities in respect of postretirement benefits that, under generally accepted accounting principles in effect at the time in question, are shown on the balance sheet as a liability, and

        (iv)  any obligation described in paragraph 6C(10) (Guaranties) for which a maximum amount is quantifiable.

        "Delayed Delivery Fee" shall have the meaning specified in paragraph 2I(2).

        "EBITDA" shall mean, for any period, the sum of Consolidated Net Earnings, plus, to the extent deducted in the determination of Consolidated Net Earnings, (i) all provisions for federal, state and other income tax, (ii) the Company's consolidated interest expense and (iii) provisions for depreciation and amortization, less, in the case of items (i) through (iii), deductions for amounts attributable to minority interests in Subsidiaries.

        "Effective Date" shall have the meaning specified in paragraph 3B.

        "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended.

        "Event of Default" shall mean any of the events specified in paragraph 7A, provided that there has been satisfied any requirement in connection with such event for the giving of notice, or the lapse of time, or the happening of any further condition, event or act, and "Default" shall mean any of such events, whether or not any such requirement has been satisfied.

        "Excess Lease Payments" shall mean all amounts payable under leases, throughout the life of such leases, whether or not such payments are capitalized in accordance with GAAP, to the extent such payments exceed $35,000,000 in the aggregate, excluding obligations arising under oil and gas leases, real estate leases for office space used by the Company or any Subsidiary, and leases for vehicles, office equipment and data processing equipment.

        "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended.

        "Existing Agreement" shall have the meaning specified in paragraph 1A.

        "Facility" shall have the meaning specified in paragraph 2A.

        "Facility Fee" shall have the meaning specified in paragraph 2I(1).

        "Fair Market Value" shall mean, at any time with respect to any property of any kind or character, the sale value of such property that would be realized in an arm's-length sale at such time between an informed and willing buyer and an informed and willing seller, under no compulsion to buy or sell, respectively.

        "Funded Debt" shall mean any Debt payable more than one year from the date of creation thereof.

        "Guarantor" shall mean each of Western Gas Resources Texas, Inc., a Texas corporation, Mountain Gas Resources, Inc., a Delaware corporation, MGTC, MIGC, Lance Oil & Gas Company, Inc., a Delaware corporation, Western Gas Wyoming, L.L.C., a Wyoming limited liability company, and each other Subsidiary of the Company that issues a Guaranty to all of the holders of Notes.

        "Guaranty" shall mean each guaranty of a Guarantor in substantially the form of Exhibit G hereto.

        "Hostile Tender Offer" shall mean, with respect to the use of proceeds of any Note, any offer to purchase, or any purchase of, shares of capital stock of any corporation or equity interests in any other entity, or securities convertible into or representing the beneficial ownership of, or rights to acquire, any such shares or equity interests, if such shares, equity interests, securities or rights are of a class which is publicly traded on any securities exchange or in any over-the-counter market, other than purchases of such shares, equity interests, securities or rights representing less than 5% of the equity interests or beneficial ownership of such corporation or other entity for portfolio investment purposes, and such offer or purchase has not been duly approved by the board of directors of such corporation or the equivalent governing body of such other entity prior to the date on which the Company makes the Request for Purchase of such Note.

        "Indenture" shall mean that certain Indenture, dated as of June 15, 1999, among the Company, the Guarantors and Chase Bank of Texas, N.A., as trustee, relating to the issuance of up to $225,000,000 aggregate principal amount of senior subordinated notes, as such Indenture is in effect on the date noted above.

        "Intercreditor Agreement" shall mean that certain Intercreditor Agreement dated as of April 26, 2001 among NCNB, as agent for the lenders parties to the NCNB Agreement, such lenders, The Prudential Insurance Company of America and Pruco Life Insurance Company, as amended by the Tenth Amendment to Loan Agreement and Amendment to Intercreditor Agreement dated as of January 3, 2003 as the provisions thereof may be from time to time further amended or waived in compliance with the terms thereof.

        "Issuance Period" shall have the meaning specified in paragraph 2B.

        "Lien" shall mean any mortgage, pledge, priority, security interest, encumbrance, deposit arrangement, lien (statutory or otherwise) or charge of any kind (including any agreement to give any of the foregoing, any conditional sale or other title retention agreement, any lease in the nature thereof, and the filing of or agreement to give any financing statement under the Uniform Commercial Code of any jurisdiction) or any other type of preferential arrangement for the purpose, or having the effect, of protecting a creditor against loss or securing the payment or performance of an obligation.

        "Long Hedge Future" shall mean an agreement, purchased on a commodities exchange or entered into with a Counterparty, that obligates the Company to purchase natural gas or liquid hydrocarbons, as the case may be, at a pre-determined price at a pre-determined time.

        "MGTC" shall mean MGTC, Inc., a Wyoming corporation.

        "MIGC" shall mean MIGC, Inc., a Delaware corporation.

        "MIGC Pledge Agreement" shall mean that certain Pledge Agreement, dated as of April 29, 1999, by MIGC in favor of the holders of the Notes, as the provisions thereof may be from time to time amended or waived in compliance with the terms thereof.

        "Minimum Rating" shall mean a rating for the senior unsecured Debt of the Company similar to the Notes (if unsecured) of at least BBB- from S & P or Baa3 from Moody's.

        "Moody's" shall mean Moody's Investors Service, Inc.

        "Multiemployer Plan" shall mean any plan that is a "multiemployer plan" (as such term is defined in Section 4001(a)(3) of ERISA).

        "NCNB" shall mean Bank of America, N.A., and its successors and assigns.

        "NCNB Agreement" shall mean that certain Loan Agreement dated as of April 29, 1999 among the Company, Bank of America, N.A., as agent, Nationsbanc Montgomery Securities LLC, as Lead Arranger, Societe Generale, as Syndication Agent, ABN AMRO Bank N.V., as Documentation Agent, and the lenders parties thereto as the provisions thereof have been or may be from time to time amended or waived in compliance with paragraph 6E.

        "Notes" shall have the meaning specified in paragraph 1B.

        "Offering Materials" shall mean, at the time any representation is made or deemed made with respect thereto under or pursuant to this Agreement by the Company, the most recent Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission prior to such time, the most recent Annual Report to stockholders sent to stockholders of the Company prior to such time, all Quarterly Reports on Form 10-Q of the Company filed with the Securities and Exchange Commission prior to such time for quarterly periods completed after the completion of the fiscal year covered by such Annual Report on Form 10-K, all quarterly reports to stockholders sent to stockholders of the Company prior to such time for quarterly periods completed after the completion of the fiscal year covered by such annual report to stockholders, all proxy statements, notices and other reports sent by the Company to its public stockholders prior to such time and after the end of such fiscal year, all registration statements (without exhibits) and all reports (including, without limitation, reports on Form 8-K) filed by the Company with the Securities and Exchange Commission or any securities exchange or other organization or association supervising trading in the Company's securities prior to such time and after the end of such fiscal year, and all press releases issued by the Company prior to such time and after the end of such fiscal year.

        "Officer's Certificate" shall mean a certificate signed in the name of the Company by an Authorized Officer of the Company.

        "Original Agreement" shall have the meaning specified in paragraph 1A.

        "Original Notes" shall have the meaning specified in paragraph 1A.

        "PBGC" shall mean the Pension Benefit Guaranty Corporation or any successor entity serving a similar function.

        "Person" shall mean and include an individual, a partnership, a joint venture, a corporation, a trust, an unincorporated organization and a government or any department or agency thereof.

        "Plan" shall mean an "employee pension benefit plan" (as defined in Section 3 of ERISA) that is or has been established or maintained, or to which contributions are or have been made, by the Company or by any trade or business, whether or not incorporated, that, together with the Company, is under common control, as described in Section 414(b) or (c) of the Code.

        "Pledge Agreement" shall mean the Company Pledge Agreement, the MIGC Pledge Agreement and each other Pledge Agreement, substantially in the form of the MIGC Pledge Agreement, delivered from time to time by a Subsidiary to the holders of the Notes pursuant to paragraph 5N, in each case as the provisions thereof may be from time to time amended or waived in compliance with the terms thereof.

        "Price Movement" shall have the meaning specified in paragraph 2I(3).

        "Prudential" shall mean The Prudential Insurance Company of America.

        "Prudential Affiliate" shall mean (i) any corporation or other entity controlling, controlled by, or under common control with, Prudential either directly or through subsidiaries and (ii) any managed account or investment fund which is managed by Prudential or a Prudential Affiliate described in clause (i) of this definition. For purposes of this definition, the terms "control", "controlling" and "controlled" shall mean the ownership, directly or through subsidiaries, of a majority of a corporation's or other entity's Voting Stock or equivalent voting securities or interests.

        "PTE 84-14" shall mean Prohibited Transaction Exemption 84-14 granted by the Department of Labor pursuant to ERISA.

        "PTE 90-1" shall mean Prohibited Transaction Exemption 90-1 granted by the Department of Labor pursuant to ERISA.

        "Purchasers" shall mean, with respect to the Series H Notes, PICA and ING Life Insurance & Annuity Company, and with respect to any other Notes, each Prudential Affiliate that purchases or agrees to purchase any Note.

        "Request for Purchase" shall have the meaning specified in paragraph 2D.

        "Required Debt Ratio" shall mean, as of any date of determination, a ratio of Adjusted Consolidated Debt to EBITDA for the period of four fiscal quarters most recently ended of 3.00 to 1.00 or less.

        "Required Holder(s)" shall mean, at any time, the holder or holders of at least 51% of the aggregate principal amount of the Notes outstanding at such time.

        "Rescheduled Closing Day" shall have the meaning specified in paragraph 2H(3).

        "Restricted Payment" shall mean (a) any dividend paid or declared by the Company or any Subsidiary on any class of the Company's stock (other than a dividend payable in shares of stock of the Company), or any other distribution made by the Company or any Subsidiary on account of any class of the Company's stock, or (b) any cash or other consideration applied, directly or indirectly, by the Company or any Subsidiary to the redemption, purchase or other acquisition of any shares of the Company's stock or (c) any payment of principal of, or any deposit of any cash, securities or other property in defeasance of, or retirement, redemption, purchase or other acquisition of any subordinated debt.

        "Restricted Subsidiary" shall have the meaning specified in the Indenture.

        "S & P" shall mean Standard & Poor's Rating Services (a division of The McGraw Hill Companies, Inc.).

        "Secured Party" shall have the meaning specified in the Pledge Agreements.

        "Securities Act" shall mean the Securities Act of 1933, as amended.

        "Senior Debt" shall mean all Debt other than Subordinated Debt.

        "Series" shall have the meaning specified in paragraph 1B.

        "Series H Closing" shall have the meaning specified in paragraph 2H(1).

        "Series H Notes" shall have the meaning specified in paragraph 2H(1).

        "Short Hedge Future" shall mean an agreement, purchased on a commodities exchange or entered into with a Counterparty, that obligates the Company to sell natural gas or liquid hydrocarbons, as the case may be, at a pre-determined price at a pre-determined time.

        "Significant Holder" shall mean (i) each Purchaser, so long as such Purchaser shall hold any Note, (ii) each affiliate of a Purchaser, so long as such affiliate shall hold any Note, or (iii) any other holder of a Note that, together with its affiliates, shall hold at least 5% of the aggregate principal amount of the Notes from time to time outstanding.

        "Significant Subsidiary" shall have the meaning specified in the Indenture.

        "Subordinated Debt" shall mean unsecured Debt of the Company for borrowed money that has no scheduled payment of principal, that may not be prepaid, redeemed or purchased earlier than January 31, 2008 and that is subordinated in right of payment to the payment of the Notes on terms typical for publicly held subordinated debt and in a manner satisfactory to the Required Holder(s).

        "Subordinated Debt Guaranties" shall mean guaranties by Subsidiaries that are Guarantors in respect of Subordinated Debt, which guaranties are subordinate in right of payment to the Guaranties on terms typical for guaranties of publicly held subordinated debt and in a manner satisfactory to the Required Holder(s).

        "Subsidiary" shall mean any corporation, association, partnership, joint venture, limited liability company or other business or corporate entity, enterprise or organization organized under the laws of any state of the United States of America, Canada, or any province of Canada, which conducts the major portion of its business in and makes the major portion of its sales to Persons located in the United States of America or Canada, and at least a majority of the combined voting power of all classes of Voting Stock of which shall, at the time as of which any determination is being made, be owned by the Company either directly or through Subsidiaries, provided that associations, joint ventures or other relationships (a) which are established pursuant to a standard form operating agreement or similar agreement or which are partnerships for purposes of federal income taxation only, (b) which are not corporations or partnerships (or subject to the Uniform Partnership Act) under applicable state law, and (c) whose businesses are limited to the exploration, development and operation of oil, gas, mineral, gas gathering or gas processing properties and interests owned directly by the parties in such associations, joint ventures or relationships, shall not be deemed to be "Subsidiaries". A "Wholly Owned Subsidiary" shall be a Subsidiary all of the stock of other form of equity interest of every class of which, except directors' qualifying shares, shall, at the time at which any determination is being made, be owned by the Company either directly or through wholly owned subsidiaries.

        "Termination Date" shall have the meaning specified in paragraph 2B.

        "Termination Event" shall mean (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations), or (ii) the withdrawal of the Company or any of its ERISA Affiliates from a Plan during a plan year in which it was a "substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under Section 4041 of ERISA, or (iv) the institution of proceedings to terminate a Plan by the PBGC, or (v) any other event or condition that might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan.

        "Transferee" shall mean any direct or indirect transferee of all or any part of any Note purchased by any Purchaser under this Agreement.

        "Treasury Yield Monitor Page" shall mean the Treasury Yield Monitor page of Standard & Poor's MMS—Treasury Market Insight (or, if Standard & Poor's shall cease to report such yields in MMS—Treasury Market Insight or shall cease to be the customary source of information for calculating yield-maintenance amounts on privately placed notes, then such source as is then the customary source of such information).

        "Voting Stock" shall mean, with respect to any corporation or other entity, any shares of stock of such corporation or equivalent equity interests of another entity whose holders are entitled under ordinary circumstances to vote for the election of directors of such corporation (or persons filling similar positions of other entities) (irrespective of whether at the time stock of any other class or classes shall have or might have voting power by reason of the happening of any contingency).

        10C.    Accounting Terms and Determinations.    All references in this Agreement to "generally accepted accounting principles" shall be deemed to refer to generally accepted accounting principles in effect in the United States at the time of application thereof, subject to the next sentence. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all determinations with respect to accounting matters hereunder shall be made, and all financial statements and certificates and reports as to financial matters required to be furnished hereunder shall be prepared, in accordance with generally accepted accounting principles, applied on a basis consistent with the audited consolidated financial statements of the Company and its Subsidiaries delivered pursuant to clause (ii) of paragraph 5A or, if no such statements have been delivered, the most recent audited financial statements referred to in clause (i) of paragraph 8B.

PARAGRAPH 11. MISCELLANEOUS.

        11A.    Note Payments.    The Company agrees that, so long as any Purchaser shall hold any Note, it will make payments of principal of, interest on and any Yield-Maintenance Amount payable with respect to such Note, which comply with the terms of this Agreement, by wire transfer of immediately available funds for credit (not later than 12:00 noon, New York City time, on the date due) to the account or accounts of such Purchaser, if any, as are specified in the Purchaser Schedule attached hereto, or, in the case of any Purchaser not named in the Purchaser Schedule or any Purchaser wishing to change the account specified for it in the Purchaser Schedule such account or accounts in the United States as such Purchaser may from time to time designate in writing, notwithstanding any contrary provision herein or in any Note with respect to the place of payment. Each Purchaser agrees that, before disposing of any Note, it will make a notation thereon (or on a schedule attached thereto) of all principal payments previously made thereon and of the date to which interest thereon has been paid. The Company agrees to afford the benefits of this paragraph 11A to any Transferee which shall have made the same agreement as the Purchasers have made in this paragraph 11A.

        11B.    Expenses.    The Company agrees, whether or not the transactions contemplated hereby shall be consummated, to pay, and save each Purchaser and any Transferee harmless against liability for the payment of, all out-of-pocket expenses arising in connection with such transactions, including (i) all document production and duplication charges and the fees and expenses of any special counsel engaged by the Purchasers or any Transferee in connection with any subsequent proposed modification of, or proposed consent under, this Agreement, whether or not such proposed modification shall be effected or proposed consent granted, and (ii) the costs and expenses, including reasonable attorneys' fees, incurred by any Purchaser or any Transferee in enforcing (or determining whether or how to enforce) any rights under this Agreement or the Notes or in responding to any subpoena or other legal process or informal investigative demand issued in connection with this Agreement or the transactions contemplated hereby or by reason of any Purchaser's or any Transferee's having acquired any Note (other than costs and expenses incurred in acquiring or merely holding a Note or interest therein), including without limitation costs and expenses incurred in any bankruptcy case. The obligations of the Company under this paragraph 11B shall survive the transfer of any Note or portion thereof or interest therein by any Purchaser or any Transferee and the payment of any Note.

        11C.    Consent to Amendments.    This Agreement may be amended, and the Company may take any action herein prohibited, or omit to perform any act herein required to be performed by it, if the Company shall obtain the written consent to such amendment, action or omission to act, of the Required Holder(s) except that, (i) with the written consent of the holders of all Notes of a particular Series, and if an Event of Default shall have occurred and be continuing, of the holders of all Notes of all Series, at the time outstanding (and not without such written consents), the Notes of such Series may be amended or the provisions thereof waived to change the maturity thereof, to change or affect the principal thereof, or to change or affect the rate or time of payment of interest on or any Yield-Maintenance Amount payable with respect to the Notes of such Series, (ii) without the written consent of the holder or holders of all Notes at the time outstanding, no amendment to or waiver of the provisions of this Agreement shall change or affect the provisions of paragraph 7A or this paragraph 11C insofar as such provisions relate to proportions of the principal amount of the Notes of any Series, or the rights of any individual holder of Notes, required with respect to any declaration of Notes to be due and payable or with respect to any consent, (iii) with the written consent of Prudential (and not without the written consent of Prudential) the provisions of paragraph 2 may be amended or waived (except insofar as any such amendment or waiver would affect any rights or obligations with respect to the purchase and sale of Notes which shall have become Accepted Notes prior to such amendment or waiver) and (iv) with the written consent of all of the Purchasers which shall have become obligated to purchase Accepted Notes of any Series (and not without the written consent of all such Purchasers), any of the provisions of paragraphs 2 and 3 may be amended or waived insofar as such amendment or waiver would affect only rights or obligations with respect to the purchase and sale of the Accepted Notes of such Series or the terms and provisions of such Accepted Notes. Each holder of any Note at the time or thereafter outstanding shall be bound by any consent authorized by this paragraph 11C, whether or not such Note shall have been marked to indicate such consent, but any Notes issued thereafter may bear a notation referring to any such consent. No course of dealing between the Company and the holder of any Note nor any delay in exercising any rights hereunder or under any Note shall operate as a waiver of any rights of any holder of such Note. As used herein and in the Notes, the term "this Agreement" and references thereto shall mean this Amended and Restated Master Shelf Agreement as it may from time to time be amended or supplemented.

        11D.    Form, Registration, Transfer and Exchange of Notes; Lost Notes    The Notes are issuable as registered notes without coupons in denominations of at least $100,000, except as may be necessary to reflect any principal amount not evenly divisible by $100,000. The Company shall keep at its principal office a register in which the Company shall provide for the registration of Notes and of transfers of Notes. Upon surrender for registration of transfer of any Note at the principal office of the Company, the Company shall, at its expense, execute and deliver one or more new Notes of like tenor and of a like aggregate principal amount, registered in the name of such transferee or transferees; provided that the Company shall not be required to register any transfer that was made in violation of the legend appearing on such Note. At the option of the holder of any Note, such Note may be exchanged for other Notes of like tenor and of any authorized denominations, of a like aggregate principal amount, upon surrender of the Note to be exchanged at the principal office of the Company. Whenever any Notes are so surrendered for exchange, the Company shall, at its expense, execute and deliver the Notes which the holder making the exchange is entitled to receive. Each installment of principal payable on each installment date upon each new Note issued upon any such transfer or exchange shall be in the same proportion to the unpaid principal amount of such new Note as the installment of principal payable on such date on the Note surrendered for registration of transfer or exchange bore to the unpaid principal amount of such Note. No reference need be made in any such new Note to any installment or installments of principal previously due and paid upon the Note surrendered for registration of transfer or exchange. Every Note surrendered for registration of transfer or exchange shall be duly endorsed, or be accompanied by a written instrument of transfer duly executed, by the holder of such Note or such holder's attorney duly authorized in writing. Any Note or Notes issued in exchange for any Note or upon transfer thereof shall carry the rights to unpaid interest and interest to accrue which were carried by the Note so exchanged or transferred, so that neither gain nor loss of interest shall result from any such transfer or exchange. Upon receipt of written notice from the holder of any Note of the loss, theft, destruction or mutilation of such Note and, in the case of any such loss, theft or destruction, upon receipt of such holder's unsecured indemnity agreement, or in the case of any such mutilation upon surrender and cancellation of such Note, the Company will make and deliver a new Note, of like tenor, in lieu of the lost, stolen, destroyed or mutilated Note.

        11E.    Persons Deemed Owners; Participations.    Prior to due presentment for registration of transfer, the Company may treat the Person in whose name any Note is registered as the owner and holder of such Note for the purpose of receiving payment of principal of and interest on and any Yield-Maintenance Amount payable with respect to such Note and for all other purposes whatsoever, whether or not such Note shall be overdue, and the Company shall not be affected by notice to the contrary. Subject to the preceding sentence, the holder of any Note may from time to time grant participations in all or any part of such Note to any Person on such terms and conditions as may be determined by such holder in its sole and absolute discretion.

        11F.    Survival of Representations and Warranties; Entire Agreement.    All representations and warranties contained herein or made in writing by or on behalf of the Company in connection herewith shall survive the execution and delivery of this Agreement and the Notes, the transfer by any Purchaser of any Note or portion thereof or interest therein and the payment of any Note, and may be relied upon by any Transferee, regardless of any investigation made at any time by or on behalf of any Purchaser or any Transferee. Subject to the preceding sentence, this Agreement, the Notes and the letter dated December 18, 2002 from Prudential to the Company embody the entire agreement and understanding between the parties hereto with respect to the subject matter hereof and supersede all prior agreements and understandings relating to such subject matter.

        11G.    Successors and Assigns.    All covenants and other agreements in this Agreement contained by or on behalf of any of the parties hereto shall bind and inure to the benefit of the respective successors and assigns of the parties hereto (including, without limitation, any Transferee) whether so expressed or not.

        11H.    Disclosure to Other Persons; Confidentiality.Except as provided in this paragraph 11H, each holder and each Person who purchases a participation in a Note or any part thereof agrees that, prior to the occurrence of a Default, it will use its best efforts to hold in confidence and not to disclose the Confidential Information. The Company acknowledges that the holder of any Note may deliver copies of any financial statements and other documents delivered to such holder, and disclose any other information disclosed to such holder, by or on behalf of the Company or any Subsidiary in connection with or pursuant to this Agreement to (i) such holder's directors, officers, employees, agents and professional consultants, (ii) any other holder of any Note, (iii) any Person to which such holder offers to sell such Note or any part thereof, (iv) any Person to which such holder sells or offers to sell a participation in all or any part of such Note, (v) any federal or state regulatory authority having jurisdiction over such holder, (vi) the National Association of Insurance Commissioners or any similar organization or (vii) any other Person to which such delivery or disclosure may be necessary or appropriate (a) in compliance with any law, rule, regulation or order applicable to such holder, (b) in response to any subpoena or other legal process or informal investigative demand, (c) in connection with any litigation to which such holder is a party or (d) in order to protect such holder's investment in such Note; provided that prior to disclosing Confidential Information to any offeree referred to in clauses (iii) and (iv) above, such holder will use its best efforts to have such offeree deliver to the Company a confidentiality agreement substantially in the form of Exhibit F hereto.

        11I.    Notices.    All written communications provided for hereunder (other than communications provided for under paragraph 2) shall be sent by first class mail or nationwide overnight delivery service (with charges prepaid) and (i) if to any Person listed in the Purchaser Schedule attached hereto, addressed to it at the address specified for such communications in the Purchaser Schedule, or at such other address as it shall have specified in writing to the Person sending such communication, and (ii) if to any Purchaser or holder of any Note which is not a Person listed in the Purchaser Schedule, addressed to it at such address as it shall have specified in writing to the Person sending such communication or, if any such holder shall not have so specified an address, then addressed to such holder in care of the last holder of such Note which shall have so specified an address to the Person sending such communication, and (iii) if to the Company, addressed to it at 12200 N. Pecos Street, Denver, Colorado 80234, Attention: General Counsel, Telecopy No. (303) 252-3362 or at such other address as the Company shall have specified to the holder of each Note in writing; provided, however, that any such communication to the Company may also, at the option of the Person sending such communication, be delivered by any other means either to the Company at its address specified above or to any Authorized Officer of the Company. Any communication pursuant to paragraph 2 shall be made by the method specified for such communication in paragraph 2, and shall be effective to create any rights or obligations under this Agreement only if, in the case of a telephone communication, an Authorized Officer of the party conveying the information and of the party receiving the information are parties to the telephone call, and in the case of a telecopier communication, the communication is signed by an Authorized Officer of the party conveying the information, addressed to the attention of an Authorized Officer of the party receiving the information, and in fact received at the telecopier terminal the number of which is listed for the party receiving the communication in the case of the Company, as provided above, and in the case of any Purchaser, as provided in the Purchaser Schedule or at such other telecopier terminal as the party receiving the information shall have specified in writing to the party sending such information.

        11J.    Payments Due on Non-Business Days.    Anything in this Agreement or the Notes to the contrary notwithstanding, any payment of principal of or interest on any Note that is due on a date other than a Business Day shall be made on the next succeeding Business Day. If the date for any payment is extended to the next succeeding Business Day by reason of the preceding sentence, the period of such extension shall be included in the computation of the interest payable on such Business Day.

        11K.    Satisfaction Requirement.    If any agreement, certificate or other writing, or any action taken or to be taken, is by the terms of this Agreement required to be satisfactory to any Purchaser, to any holder of Notes or to the Required Holder(s), the determination of such satisfaction shall be made by such Purchaser, such holder or the Required Holder(s), as the case may be, in the sole and exclusive judgment (exercised in good faith) of the Person or Persons making such determination.

        11L.    Governing Law.THIS AGREEMENT SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, AND THE RIGHTS OF THE PARTIES SHALL BE GOVERNED BY, THE LAW OF THE STATE OF NEW YORK.

        11M.    Severability.    Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

        11N.    Descriptive Headings.    The descriptive headings of the several paragraphs of this Agreement are inserted for convenience only and do not constitute a part of this Agreement.

        11O.    Counterparts.    This Agreement may be executed simultaneously in two or more counterparts, each of which shall be deemed an original, and it shall not be necessary in making proof of this Agreement to produce or account for more than one such counterpart.

        11P.    Binding Agreement.    When this Agreement is executed and delivered by the Company and Prudential, it shall become a binding agreement between the Company and Prudential. This Agreement shall also inure to the benefit of each other Purchaser which shall have executed and delivered a Confirmation of Acceptance, and each such other Purchaser shall be bound by this Agreement to the extent provided in such Confirmation of Acceptance.

        11Q.    Agreement Regarding Paragraph 6A(3).    Prudential and the holders of the Notes agree that if the NCNB Agreement is permanently amended on or before June 30, 2003 to increase the percentage contained in a covenant similar to paragraph 6A(3) from "35%" to "40%," Prudential and the holders of the Notes will enter into an amendment similar to the amendment to the NCNB Agreement to effect such modification; provided, however, that if such covenant is subsequently modified to decrease such percentage, the Company shall promptly notify Prudential and enter into an amendment to this Agreement to decrease the percentage in paragraph 6A(3) to the percentage contained in the NCNB Agreement.

        If you are in agreement with the foregoing, please sign the form of acceptance on the enclosed counterparts of this letter and return the same to the Company, whereupon this Agreement shall become a binding agreement between the Company and Prudential effective as of January 13, 2003.

Very truly yours,
WESTERN GAS RESOURCES, INC.
By	Executive Vice President and Chief Financial Officer

The foregoing Agreement is hereby accepted as of the date first above written.
THE PRUDENTIAL INSURANCE COMPANY OF AMERICA
By	Vice President
PRUCO LIFE INSURANCE COMPANY
By	Vice President
PRUDENTIAL INVESTMENT MANAGEMENT, INC.
By	Vice President

ING LIFE INSURANCE & ANNUITY COMPANY
By:	Prudential Private Placement Investors, L.P. (as Investment Advisor)
By:	Prudential Private Placement Investors, Inc. (as its General Partner)
By:	Vice President

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Exhibit 10.29

EX-11.1

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Exhibit 11.1

WESTERN GAS RESOURCES, INC.
COMPUTATION OF PER SHARE EARNINGS
DECEMBER 31, 2002

		Weighted Average Shares Of Common Stock Outstanding	Net Income			Earnings Per Share Of Common Stock
Net income			$	50,589,000
Weighted average shares of common stock outstanding		32,952,543
Less preferred stock dividends:
	$2.28 cumulative preferred stock			(1,265,053	)
	Special dividend on redemption of $2.28 cumulative preferred stock			(688,000	)
	$2.625 cumulative convertible preferred stock			(7,245,000	)
		32,952,543	$	41,390,947
Basic earnings per share of common stock						$	1.26
Assume exercise of common stock equivalents (Anti-dilutive common stock equivalents are not used in this calculation)		655,017
		33,607,560	$	41,390,947
Fully diluted earnings per share of common stock						$	1.23

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Exhibit 11.1

EX-21

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Exhibit 21

Subsidiaries of Western Gas Resources, Inc.

Name of Subsidiary		Relationship
To review
1)	MIGC, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
2)	MGTC, Inc.	Wholly owned subsidiary of MIGC, Inc.
3)	Western Gas Resources—Texas, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
4)	Mountain Gas Resources, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
5)	Western Power Services, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
6)	WGR Canada, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
7)	Lance Oil & Gas Company, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
8)	Mountain Gas Transportation, Inc.	Wholly owned subsidiary of Mountain Gas Resources, Inc.
9)	Western Gas Wyoming, L.L.C.	Wholly owned subsidiary of Western Gas Resources, Inc.
10)	Western Gas Resources—Westana, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.
11)	Western Gas Resources—Oklahoma, Inc.	Wholly owned subsidiary of Western Gas Resources, Inc.

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Exhibit 21

EX-23.1

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CONSENT OF INDEPENDENT ACCOUNTANTS

        We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-98107, No. 333-103682, No. 333-103684, No. 33-66516, No. 33-54741, No. 333-00903 and No. 333-13099) and in the Registration Statements on Form S-8 (No. 33-67834, No. 333-29711, No. 333-75732, No. 333-95255, No. 333-95259, No. 333-13099, No. 033-58852) of Western Gas Resources, Inc. of our report dated February 19, 2003 relating to the financial statements, which appears in this Annual Report on Form 10-K.

PricewaterhouseCoopers LLP

Denver, Colorado
March 21, 2003

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CONSENT OF INDEPENDENT ACCOUNTANTS

EX-23.2

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Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

        We hereby consent to the use of our name and information related to reserves in the Annual Report on Form 10-K of Western Gas Resources, Inc. and Subsidiaries (the "Company") for the year ended December 31, 2002.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/  C.H. (SCOTT) REES III C.H. (Scott) Rees III President and Chief Operating Officer

Dallas, Texas
March 6, 2003

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Exhibit 23.2

EX-99.1

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Exhibit 99.1

Certification of CEO and CFO Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the Annual Report on Form 10-K of Western Gas Resources (the "Company") for the fiscal year ended December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Peter A. Dea, as Chief Executive Officer of the Company, and William J. Krysiak, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

        (1)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

        (2)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Peter A. Dea Name: Peter A. Dea
Title: Chief Executive Officer and President
Date: March 21, 2003

/s/ William J. Krysiak Name: William J. Krysiak
Title: Executive Vice President—Chief Financial Officer
Date: March 21, 2003

        This certification accompanies the Report pursuant to § 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.

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Exhibit 99.1

Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002