WESTERN GAS RESOURCES INC - 10-Q Quarterly Report

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

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

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

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

On August 1, 2002, there were 33,004,382 shares of the registrant's Common Stock outstanding.

WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(Dollars in thousands, except share data)

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

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(Dollars in thousands)

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

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
(Dollars in thousands, except share and per share amounts)

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

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(Unaudited)
(Dollars in thousands, except share amounts)

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

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2001. The interim consolidated financial statements as of June 30, 2002 and for the three and six month periods ended June 30, 2002 and 2001 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly present the results for such periods. The results of operations for the three and six months ended June 30, 2002 are not necessarily indicative of the results of operations expected for the year ended December 31, 2002.

Prior year's amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2002.

Earnings per share of common stock is 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. We declared preferred stock dividends of $2.1 million and $2.6 million for the three months ended June 30, 2002 and 2001, respectively, and $4.3 million and $5.2 million, respectively, for the six month period ended June 30, 2002 and 2001. Common stock options and our $2.625 Cumulative Convertible Preferred Stock, which are potential common shares, had a dilutive effect on earnings and increased the weighted average number of shares of common stock outstanding by 785,326 and 4,494,345 for the three-month periods ended June 30, 2002 and 2001, respectively, and by 744,565 and 4,473,008 for the six months ended June 30, 2002 and 2001, respectively. The numerators and the denominators for these periods were adjusted to reflect these potential shares in calculating fully diluted earnings per share.

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. ("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.

Westana. In February 2001, 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 2001 of a 50% equity interest in the Westana Gathering Company are reflected in revenues in Other, net on the Consolidated Statement of Operations. Beginning in March 2001, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses.

Granger Complex. In May 2001, we acquired the remaining 50% interest in a portion of a gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation.

approximates the book value of this facility. The closing of the sale is subject to various preferential purchase rights and is expected to occur in September 2002. If the sale closes, it will be effective on June 1, 2002. This asset is reflected in Assets held for sale at June 30, 2002. During the second quarter and six months ended June 30, 2002, this facility generated net after-tax earnings of approximately $282,000, or $.01 per share of common stock, and $560,000, or $.02 per share of common stock, respectively. We believe the results from this facility are immaterial for separate presentation as a discontinued operation. The proceeds from this sale will be used to reduce amounts outstanding on our Revolving Credit Facility.

Corporate Offices. 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 will total $12.0 million. Our corporate offices will be relocated to this space in the fourth quarter of 2002. We intend to sell the 52,000 square foot office building we currently occupy. The office building is reflected as an Asset held for sale at June 30, 2002.

Officer Loans. 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 was continually employed by us and upon a resolution of the board of directors. In May and July 2002, we forgave loans related to 37,500 shares of Common Stock totaling $636,000. After giving effect to the forgiveness, loans related to 37,500 shares of Common Stock totaling $637,000, remain outstanding. Pursuant to agreements entered into in 1995 and 2001, all remaining loans will be forgiven by May 2003.

In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities that, for various reasons, are not designated or qualified as hedges under SFAS 133.

The net gain recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first six months of 2002 from hedging activities was $12.3 million. This is net of a loss of $132,000 resulting from hedge ineffectiveness due to the use of crude oil swaps in hedging the variability in the sales price of normal butane. Overall, our hedges are expected to continue to be "highly effective" under SFAS No. 133 in the future and no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings based on the actual sales of the hedged gas or NGLs. Based on prices as of June 30, 2002, approximately $5.3 million of gains in Accumulated other comprehensive income will be reclassified to earnings in the next twelve months with the remainder reclassified by the end of 2003.

Interest paid was $14.1 million and $15.1 million for the six months ended June 30, 2002 and 2001, respectively.

No estimated tax payments were made during the six months ended June 30, 2002, and $9.4 million in estimated tax payments were made during the six months ended June 30, 2001.

We operate 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 our internal financial reporting package. These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations.

In the Gas Gathering, Processing and Treating segment, we connect producers' wells (including those of the Exploration and Production segment) to our gathering systems for delivery to our processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. The Marketing segment sells the residue gas and NGLs extracted at our processing and treating facilities. In this segment, we recognize revenue for our services at the time the service is performed.

The activities of the Exploration and Production segment include the exploration and development of gas properties primarily in the basins where our gathering and processing facilities are located. The Marketing segment sells the majority of the production from these properties.

Our 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 our gathering, processing, treating and production assets. Also included in this segment are our 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. We record revenues on our gas and NGL marketing activities on a gross sales versus sales net of purchases basis as we obtain title to all of the gas and NGLs that we buy including third-party purchases, and bear the risk of loss and credit exposure on these transactions.

The Transportation segment reflects the operations of our MIGC and MGTC pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas for our Marketing segment and other third parties. In this segment, we realize 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.

Included in the Corporate column are gains and losses associated with our equity gas and NGL hedging program of approximately $3.0 million and $(1.7) million for the three months ended June 30, 2002 and June 30, 2001, respectively, and approximately $12.3 million and $(16.0) million for the six months ended June 30, 2002 and 2001, respectively.

The following table sets forth our segment information as of and for the three and six months ended June 30, 2002 and 2001 (dollars in thousands). Due to our 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.

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. We have not yet determined the impact that the adoption of SFAS No. 143 will have on our earnings or financial position.

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 transactions occurring after May 15, 2002. Through the rescission of FAS 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. We do not believe SFAS No. 145 will have a material impact on our earnings or financial position.

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 (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)." We do not believe that SFAS No. 146 will have a material impact on our earnings or financial position.

Reference is made to "Part II—Other Information—Item 1. Legal Proceedings," of this Form 10-Q.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis relates to factors which have affected our consolidated financial condition and results of operations for the three and six months ended June 30, 2002 and 2001. Prior year amounts have been reclassified as appropriate to conform to the presentation used in 2002. You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document. This section, as well as other sections in this Form 10-Q, contain "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. In addition to the important factors referred to herein, numerous factors affecting the gas processing or the oil and gas industry generally and in the specific markets for gas and NGLs in which we operate could cause actual results to differ materially from those in such forward-looking statements.

Three and six months ended June 30, 2002 compared to the three and six months ended June 30, 2001
(Dollars in thousands, except per share amounts and operating data).

Net income decreased $15.7 million and $48.3 million for the three and six months ended June 30, 2002, respectively, compared to the same periods in 2001. The decrease in net income for these periods is primarily attributable to significantly lower gas and NGL prices in the second quarter of 2002 compared to the same period last year and lower margins per unit earned in our Marketing segment. These reductions more than offset increased production from the Powder River Basin coal bed methane development.

Revenues from the sale of gas decreased $247.8 million to $510.2 million for the three months ended June 30, 2002 compared to the same period in 2001. This decrease was due to a decline in product prices in 2002. Average gas prices realized by us decreased $1.46 per Mcf to $3.07 per Mcf for the quarter ended June 30, 2002 compared to the same period in 2001. Included in the realized gas price were approximately $6.4 million of gains recognized in the three months ended June 30, 2002 related to futures positions on equity gas volumes. We have entered into additional futures positions for the majority of our equity gas for the remainder of 2002 and to a lesser extent in 2003. Average gas

sales volumes remained relatively constant at 1,855 MMcf per day for the quarter ended June 30, 2002 compared to the same period in 2001.

Revenues from the sale of gas decreased $748.8 million to $1,055.8 million in the six months ended June 30, 2002 compared to the same period in 2001. This decrease was primarily due to a decline in product prices, which more than offset an increase in sales volume in the second quarter of 2002. Average gas prices realized by us decreased $2.95 per Mcf to $2.73 per Mcf in the six months ended June 30, 2002 compared to the same period in 2001. Included in the realized gas price were approximately $16.3 million of gains recognized in the six months ended June 30, 2002 related to futures positions on equity gas volumes. Average gas sales volumes increased 395 MMcf per day to 2,150 MMcf per day in the six months ended June 30, 2002 compared to the same period in 2001 primarily due to an increase in the sale of third-party product.

Revenues from the sale of NGLs decreased $34.6 million in the second quarter of 2002 compared to the same period in 2001. This decrease is primarily due to a decline in product prices and to a lesser extent to a reduction in sales volume. Average NGL prices realized by us decreased $0.12 per gallon to $0.41 per gallon in the second quarter of 2002 compared to the same period in 2001. Included in the realized NGL price was approximately $3.4 million of losses recognized in the second quarter of 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 the remainder of 2002. Average NGL sales volumes decreased 245 MGal per day to 2,125 MGal per day in the second quarter of 2002 compared to the same period in 2001. This decrease is primarily due to an intentional reduction in the sale of third-party product as these types of sales are generating minimal margins.

Revenues from the sale of NGLs decreased approximately $99.3 million in the six months ended June 30, 2002 compared to the same period in 2001. This decrease is primarily due to a reduction in product prices and to a lesser extent to a reduction in sales volume. Average NGL prices realized by us decreased $0.19 per gallon to $0.39 per gallon in the six months ended June 30, 2002 compared to the same period in 2001. Included in the realized NGL price were approximately $4.0 million of losses recognized in the six months ended June 30, 2002 related to futures positions on equity NGL volumes. Average NGL sales volumes decreased 265 MGal per day to 2,035 MGal per day in the six months ended June 30, 2002 compared to the same period in 2001. This decrease is primarily due to an intentional reduction in the sale of third-party product as these types of sales were generating minimal margins and due to credit concerns with our customers in the NGL industry. Also contributing to the reduction in overall sales volume was a decrease in the sale of product produced at our facilities as we rejected ethane for a portion of the six-month period ended June 30, 2002.

Product purchases decreased by $256.3 million and $798.3 million for the quarter and six months ended June 30, 2002 compared to the same period in 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 quarter and six months ended June 30, 2002 from 90% and 91% for the same periods in 2001, respectively. The decrease in the product purchase percentage resulted from reduced product prices.

Marketing margins on residue gas averaged $0.08 and $0.05 per Mcf in the second quarter and the six months ended June 30, 2002, respectively. This represents a decrease as compared to the margin realized during both the second quarter and six months ended June 30, 2001 of $0.10 per Mcf. The decrease in margin for the quarter and six months ended June 30, 2002 compared to the 2001 periods primarily resulted from the mark-to-market of transactions originated in 2001 utilizing our firm transportation and storage capacity. These transactions resulted in higher margins than the transactions completed in the 2002 periods. Under mark-to-market accounting, the margin anticipated to be realized over the term of the transaction is recorded in the month of origination. To the extent this amount includes margin to be recognized beyond the current quarter, it is included in the financial statement

caption Unrealized gain (loss) on marketing activities. Marketing margins on NGLs averaged approximately $0.006 per gallon in the second quarter of 2002 and $0.008 per gallon in the six months ended June 30, 2002. This margin remained relatively constant as compared to the same periods in 2001. There is no assurance, however, that these market conditions for our gas and NGL products and related margins will continue in the future, that we will be in a similar position to benefit from them or that we will continue to originate the same amount of transactions in future quarters. In the second quarter of 2002, we accrued a total of $1.2 million for doubtful accounts, primarily due to the bankruptcy filing of a large mid-western co-op in that quarter. Overall, in the first six months ended June 30, 2002, we accrued a total of $1.6 million for doubtful accounts. These accruals are not included in the calculation of the marketing margins and are reported in Selling and administrative expenses.

Plant operating expense increased $1.6 million in the second quarter of 2002 and increased by $3.4 million in the six months ended June 30, 2002 compared to the same periods in 2001. This increase is 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 $44,000 and decreased by $2.2 million in the second quarter and the six months ended June 30, 2002, respectively, as compared to the same periods in 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. LOE expenses in the Powder River Basin coal bed development averaged $0.54 per Mcf in second quarter and $0.48 per Mcf in the six months ended June 30, 2002. This represents increases of $0.19 per Mcf and $0.11 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.

Selling and administrative expenses increased by $4.3 million and $4.6 million in the second quarter and six months ended June 30, 2002, respectively, due to higher health insurance costs, increased reserves for doubtful accounts and higher compensation expenses.

Depreciation, depletion and amortization increased by $2.0 million and $5.4 million in the second quarter and the six months ended June 30, 2002, respectively, as compared to the same periods in 2001 primarily as a result of our increasing operations in the Powder River Basin coal bed methane development.

Cash flows from operating activities decreased by $70.1 million in the first six months of 2002 compared to the same period in 2001. This reduction was primarily due to a decrease in net income in the first first six months of 2002 compared to the prior year and the timing of cash receipts and payables.

Cash flows used in investing activities increased by $26.9 million in the first six months of 2002 compared to the same period in 2001. This increase was primarily due to the sale of our Bethel Treating facility in the first quarter of 2001.

Cash flows from financing activities increased by $71.1 million in the first six months of 2002 compared to the same period in 2001. This increase was due to the application of the proceeds received in the sale of our Bethel Treating facility in the first quarter of 2001 to reduce the amounts outstanding under our Revolving Credit Facility.

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. ("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.

Toca Processing Facility. In June 2002, we entered into an agreement for the sale of our Toca processing facility in Louisiana. The sale price is $32.5 million, subject to accounting adjustments, and approximates the book value of this facility. The closing of the sale is subject to various preferential purchase rights and is expected to occur in September 2002. If the sale closes, it will be effective on June 1, 2002. This asset is reflected in Assets held for sale at June 30, 2002. During the second quarter and six months ended June 30, 2002, this facility generated net after-tax earnings of approximately $282,000, or $0.01 per share of common stock, and $560,000, or $0.02 per share of common stock, respectively. We believe the results from this facility are immaterial for separate presentation as a discontinued operation. The proceeds from this sale will be used initially to reduce amounts outstanding on our Revolving Credit Facility.

Officer Loans. In 1989, we loaned to our officers at that time, an amount sufficient to exercise their options under our stock options plans. The loans and accrued interest were to be forgiven if the officer was continually employed by us and upon a resolution of the board of directors. In May and July 2002, we forgave loans related to 37,500 shares of Common Stock totaling $636,000. After giving effect to the forgiveness, loans related to 37,500 shares of Common Stock totaling $637,000, remain outstanding. Pursuant to agreements entered into in 1995 and 2001, all remaining loans will be forgiven by May 2003.

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 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 over the course of the next three to five years; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

Double Proven Natural Gas Reserves and Equity Production of Natural Gas. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin coal bed methane, CBM, development, in the Green River Basin and in the Sand Wash Basin. We have acquired drilling rights on approximately 827,000 net acres in these and other Rocky Mountain basins. At December 31, 2001, we had proved developed and undeveloped reserves of approximately 476 billion cubic feet equivalent, Bcfe, on a portion of this acreage position. In total this represents an increase of approximately 15% in our proved reserves from December 31, 2000. Reserve life of our

producing properties remains at over 13 years. Our production during the first six months of 2002 as compared to the same period in 2001 increased by 29% to 21.9 Bcfe. In the full year of 2001, we replaced 275% of that year's production. All our 2001 reserve growth and our production growth in the first six months of 2002 was achieved organically through the drill bit. As of December 31, 2001, we estimated that there was a net total of 2.1 trillion cubic feet, Tcf, of probable and possible reserves associated with our undeveloped acreage in these areas. In the Powder River Basin, this potential lies in over 10,000 development locations in the Big George, Wyodak and related coals if the play is fully successful. In the Green River Basin, our reserve potential lies in the development of 80-acre and 40-acre locations on our leasehold on the Pinedale Anticline.

We are also actively seeking to add another core project 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. The addition of another core project will ideally result in additional investment opportunities in our midstream operations.

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

Our midstream operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather, process or treat natural gas produced on acreage dedicated to us by third parties or produced by us. We contract for production from newly developed acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering, processing or treating at our facilities. At December 31, 2001, the estimated reserves dedicated to our midstream facilities totaled 3.2 Tcf. This includes our estimate of future third party production and our proven reserves, but does not include our 2.1 Tcf of probable and possible reserves. The estimated third-party reserves dedicated 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 2001, including the reserves developed by us and associated with our partnerships and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 190% of throughput. In the first six months of 2002, we spent approximately $27.0 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.

Optimize Annual Returns. To optimize our annual returns, we will focus our efforts in our primary operating areas of the Powder River and Green River Basins in Wyoming, the Anadarko Basin in Oklahoma and the Permian Basin in west Texas. We review the economic performance and growth opportunities of each of our operating facilities to ensure that a satisfactory rate of return is achieved. If an operating facility is not generating targeted returns or is outside 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. Additionally, we routinely evaluate our business for methods to reduce our operating and administrative costs, including the implementation of automation and information technology.

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, efficient operation of our facilities and our ability to obtain financing at favorable terms.

We believe that the amounts available to be borrowed under the Revolving Credit Facility, together with net cash provided by operating activities will provide us with sufficient funds to connect new reserves, maintain our existing facilities, complete our current capital expenditure program and make any scheduled debt principal payments through 2002. We have from time to time renegotiated the Revolving Credit Facility to extend the maturities of the facility. 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 our debt service and preferred stock dividend requirements for 2002.

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. Higher gas prices, improved technology, e.g., 3-D seismic and horizontal drilling, and increased pipeline capacity from the Rocky Mountain region have stimulated drilling in many of our operating areas. The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, 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 ourselves and third-parties. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A reduction in any of these activities could have a material adverse effect on our financial condition and results of operations.

We have effective shelf registration statements filed with the Securities and Exchange Commission for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock.

Our sources and uses of funds for the six months ended June 30, 2002 are summarized as follows (dollars in thousands):

Sources of funds:
	Borrowings under the Revolving Credit Facility		$	537,000
	Proceeds from the dispositions of property and equipment			465
	Net cash provided by operating activities			68,238
	Proceeds from exercise of common stock options			6,191

		Total sources of funds	$	611,894

Uses of funds:
	Payments related to long-term debt (including debt issue costs)		$	522,100
	Capital expenditures			57,855
	Dividends paid			7,546
	Contributions to equity investees			6,583
	Other			114

		Total uses of funds	$	594,198

Inventories and Storage Capacity. Access to storage capacity is a significant element of our marketing strategy. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of June 30, 2002, we had contracts in place for approximately 14.3 Bcf of storage capacity at various third-party facilities. A contract for storage capacity for three Bcf expired in April 2002. The fees associated with these contracts during 2002 will average $0.32 per Mcf of annual capacity. The associated contract periods have an average tenor of four years. The majority of the current agreements have a term of three years or less. Our agreement with the longest duration expires in 2028. It is for storage capacity of 281,000 Mcf and has an associated annual fee of $78,000. At June 30, 2002, we held gas in our contracted storage facilities and in imbalances of approximately 16.3 Bcf at an average cost of $2.50 per Mcf compared to 11.5 Bcf at an average cost of $5.61 per Mcf at June 30, 2001. These positions are for storage withdrawals within the next eighteen months. We acquire derivatives to minimize our exposure to price movements related to our inventories and storage capacity. Under mark-to-market accounting, our inventories in these storage facilities and the related derivatives are marked-to-market and the expected profit to be earned on these transactions is recorded in the month of origination. We have also entered into a precedent agreement for 2.4 Bcf of annual capacity for storage in a facility, which is not completed. We anticipate the completion 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 June 30, 2002, we held NGLs in storage at various third-party facilities of 3,933 MGal, consisting primarily of propane and normal butane, at an average cost of $0.30 per gallon compared to 6,930 MGal at an average cost of $0.45 per gallon at June 30, 2001.

We acquire derivatives to minimize our exposure to price movements related to our inventories and storage capacity. Under mark-to-market accounting, our inventories in these storage facilities and the related derivatives are marked to market and the expected profit to be earned on these transactions is recorded in the month of origination.

Firm Transportation Capacity. Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. As of August 1, 2002, we had contracts for approximately 633 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 166 MMcf per day of gas from Wyoming to the Mid-Continent. This utilizes a total of approximately 461 MMcf per day of firm capacity on three separate pipelines. Our remaining firm capacity consists of 106 MMcf per day to markets within the Rocky Mountains and 66 MMcf per day contracted in various other markets throughout the country.

A portion of this firm transportation capacity was contracted for use in our marketing operation. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 50 MMcf per day of firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During the first six months of 2002, these types of transactions have been very profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. To the extent these transportation contracts were acquired for our Marketing segment, they are derivative contracts as defined by SFAS No. 133 and are marked to market.

The fixed fees associated with our contracts for firm transportation capacity during 2002 will average approximately $0.14 per Mcf per day, and the associated contract periods range from three months to fifteen years. In addition, some contracts contain provisions requiring us to pay the fees associated with these contracts whether or not the transportation is used. In conjunction with an expansion of the Trailblazer pipeline in May 2002, we entered into a ten-year contract for an additional 57.5 MMcf per day of firm transportation capacity on this pipeline.

Operating Leases. Primarily to support our growing development in the Powder River coal bed development, we have entered into several operating leases for compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. As of June 30, 2002, we had leased a total of 84 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. At June 30, 2002, we had 23 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. Additionally, at June 30, 2002, we had eight compressor units currently in construction on which we have paid deposits of $2.6 million. We anticipate entering into additional leases during the remainder of 2002 to accommodate this equipment.

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 will total approximately $12.0 million. Our corporate offices will be relocated to this space in the fourth quarter of 2002.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2002 is as follows (dollars in thousands):

Capital expenditures related to existing operations totaled approximately $64.4 million during the first half of 2002, consisting of the following: (i) approximately $28.4 million related to gathering, processing, treating and pipeline assets, including $3.0 million for maintaining existing facilities; (ii) approximately $34.9 million related to exploration and production and lease acquisition activities; and (iii) approximately $1.1 million for miscellaneous items. 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 22%, respectively, of the total capital expenditures in the first six months of 2002.

We expect capital expenditures related to existing operations to be approximately $143.5 million during 2002. The 2002 budget represents an approximate 13% decrease from the amount expended in 2001 due to an expectation of lower commodity prices. The 2002 capital budget consists of the following: (i) approximately $71.7 million related to gathering, processing, treating and pipeline assets, including $6.4 million for maintaining existing facilities; (ii) approximately $68.9 million related to exploration and production and lease acquisition activities; and (iii) approximately $2.9 million for miscellaneous items. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 52% and 24%, respectively, of the total 2002 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2002 will not change. We anticipate that funds for the 2002 capital budget will be provided primarily by internally generated cash flow. This budget may be increased to provide for acquisitions if approved by our board of directors.

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin coal bed gas 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, in the first six months of 2002, we continued to be the largest producer of natural gas (together with our co-developer, the largest gatherer of natural gas and the largest gas transporter out of this basin. At June 30, 2002, we held the drilling rights on approximately 524,000 net acres in this basin. As of December 31, 2001, we had established proven developed and undeveloped reserves totaling 393 Bcfe on a portion of this acreage. This represented a 12% increase in proved reserves as compared to December 31, 2000. As of December 31, 2001, we estimated that there was a net total of 1.9 Tcf of probable and possible reserves associated with our undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves due to geologic, regulatory, commodity price and lease expiration risks.

We plan to participate in over 900 gross wells in 2002, of which 675 were drilled in the first six months. The average drilling and completion cost for our coal bed methane gas wells is approximately $90,000 per well with average reserves per successful well of approximately 278 MMcf. Our average finding and development costs in this area are estimated to be approximately $0.42 per Mcf in 2002. As deeper wells are drilled to the Big George coal, reserves per well are expected to increase as will the average cost per well. It is expected that the deeper Big George wells will result in a higher rate of return. Our share of production from wells in which we own an interest has increased from an average of approximately 83 MMcfe per day in the six months ended June 30, 2001 to 109 MMcfe per day in the six months ended June 30, 2002. As of August 1, 2002, we were producing an average of 118 MMcf per day, net to our interest. We currently anticipate production rates of 137 net MMcf per day (350 gross MMcf per day) from this area by the end of 2002. As of June 30, 2002, we had approximately 1,290 wells that have been drilled but have not yet produced a total of 10 MMcf and are not producing more than 10 Mcf per day. Of this total, approximately 200 wells are under performing relative to our expectations based upon their location and the performance of other wells in the area. In addition, approximately 300 wells, the majority of which are within the Hoe Creek area of the Powder River Basin, are currently dewatering. In the Hoe Creek area, core data indicates that the coal is under

saturated with gas relative to our previous reserve assumptions, and may therefore require more extensive dewatering and result in lower recoverable reserves per well. While we have not updated our 2001 reserve analysis, based on our experience thus far in 2002, we anticipate that the Hoe Creek wells and some of the other wells may not achieve our original estimate of production or reserves. All of the remaining areas under development in the Wyodak coal continue to produce at or above our forecasted levels.

We are currently evaluating twelve pilot areas and one development area in the Big George. By the end of 2002, we expect to have drilled approximately 425 gross wells in the Big George coal area. Several of these pilot areas are in close proximity to four producing Big George areas, including our All Night Creek development area. Production from these areas is increasing and in the first half of 2002, they were producing over 33 MMcf per day. As of August 4, 2002, our All Night Creek area was producing 10.7 gross MMcf per day of gas from 63 wells with an additional 27 wells in the de-watering stage and another 48 awaiting connection to our gathering system. At December 31, 2001, we had proven reserves of 26 Bcfe in the Big George coal.

Future drilling on federal acreage will be delayed subject to completion of the Powder River Basin Oil & Gas Environmental Impact Statement (EIS). The comment period for the draft EIS ended on May 15, 2002. Although the Environmental Protection Agency, EPA, has submitted a negative comment letter with respect to the draft EIS, the BLM and EPA are engaged in discussions. We believe that they will reach agreement as to the issues included in the comment letter. We anticipate the study to be completed late in the fourth quarter of 2002 or early in 2003. However, we can make no assurance the EIS will be completed within this time period. Our drilling plans for 2002 are not expected to be substantially impacted by this study due to our large inventory of non-federal drilling locations and the issuance of drilling permits by the Bureau of Land Management, BLM, for approximately 250 well locations to prevent drainage of federal acreage. 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.

Additionally, the Wyoming Department of Environmental Quality, DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of wells on our acreage producing from the Wyodak formation drain into these areas. The Wyoming and Montana DEQ offices have reached agreement on procedures for discharging and monitoring water into the Powder River drainage areas, in which most of our Big George prospects are located. The Wyoming DEQ has begun to release permits on a limited basis to the Powder River drainage area, however, only when it can be demonstrated that none of the discharge water will reach the Powder River itself. The Wyoming DEQ office has not yet determined the numeric standards, if any, to be implemented for sodium absorption ratio, electro-conductivity and total dissolved solids. If the Wyoming DEQ does not implement numeric standards for some or all of the contaminants, we believe that they would likely adopt qualitative standards specific to the individual drainage areas. We can make no assurance that the conditions under which additional permits will be granted will not impact the level of our drilling or the cost or timing of the associated production.

On April 26, 2002, the Interior Board of Land Appeals (IBLA) ruled that the Bureau of Land Management (BLM) did not comply with the National Environmental Policy Act (NEPA) prior to issuing three federal oil and gas leases held by an unaffiliated third party in the Powder River Basin, 156 IBLA at 358-59. 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 Powder River Basin Environmental Impact Statement 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. 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.

In addition to the revenues earned from the production of our coal bed methane gas, we also earn fees for gathering and transporting the natural gas. During the first half of 2002, we were gathering 354 MMcf per day of our own production and that of other third-party producers. Of that volume, approximately 131 MMcf per day was transported through our wholly- owned MIGC pipeline.

Our capital budget in the Powder River Basin coal bed development provides for expenditures of approximately $74.8 million during 2002 of which $36.5 million was spent in the first six months of 2002. This capital budget includes approximately $51.0 million for drilling costs for our interest in over 900 wells, production equipment and undeveloped acreage and $23.8 million for gathering lines and installation of compression. We have entered into several operating leases for compression equipment. As of June 30, 2002, we had leased a total of 84 compression units. These leases have terms ranging from two to ten years with fair market purchase options available at various times during the lease. Depending upon future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. 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. Recently, our co-developer in this area has publicly disclosed financial difficulties. We are currently unable to predict the impact, if any, of our co-developers financial difficulties on the future pace of development in the Powder River Coal bed area.

In 1998, we joined with other industry participants to form Fort Union Gas Gathering, L.L.C., to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River Basin in northeast Wyoming. We own a 13% equity interest in Fort Union and are the construction manager and field operator. The gathering header initially had a capacity of approximately 435 MMcf per day. The header delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. The gathering pipeline went into service in the third quarter of 1999. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by us of approximately $900,000. In 1999, we entered into a ten-year agreement for firm gathering services on 60 MMcf per day of capacity at $0.14 per Mcf on Fort Union. In the fourth quarter of 2000, we and the other participants in Fort Union approved an expansion of the system. Construction of the 62-mile expansion was completed in the third quarter of 2001 and brought the system's capacity to 635 MMcf per day. The expansion costs totaled approximately $22.0 million and were project financed by Fort Union. In the fourth quarter of 2001, we invested approximately $500,000 as an equity contribution to Fort Union in conjunction with the project financing. Also in connection with the expansion, we increased our commitment for firm gathering services, effective December 2001, to a total of 83 MMcf per day of capacity at $0.14 per Mcf. All participants in Fort Union have guaranteed the project financing on a proportional basis resulting in our guarantee of $6.7 million of the debt of Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Green River Basin. Our assets in the Green River Basin of southwest Wyoming are comprised of the Granger and Lincoln Road facilities, or collectively the Granger Complex, our 50% equity interest in Rendezvous Gas Services, L.L.C., our Red Desert facility and production in the Jonah Field and Pinedale Anticline areas. These facilities have a combined operational capacity of 327 MMcf per day and processed an average of 192 MMcf per day in the first six months of 2002. Our capital budget in this area provides for expenditures of approximately $34.8 million during 2002 of which $14.1 million was spent in the first six months of 2002. This capital budget includes approximately $11.6 million for drilling costs and production equipment and approximately $23.2 million related to the gathering systems, plant facilities and additional capital contributions to Rendezvous. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

In September 2001, we signed an agreement with Questar for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. Both we and Questar contributed our respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to Rendezvous. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous began construction of additional gas gathering pipelines and compression facilities with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale Anticline. The first phase of our 50% owned Rendezvous gathering expansion into the Pinedale Anticline is completed. We expect the second phase of the construction to be completed in October 2002. The first two phases will add a total of 175 MMcf per day of gathering capacity. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of this expansion is $44.0 million, of which our share will be $22.0 million. Of this $22.0 million, approximately $18.3 million is expected to be spent in 2002 and is included in our capital expenditure budget.

At June 30, 2002, we owned approximately 245,000 gross oil and gas leasehold acres, or approximately 35,000 net acres, in the Jonah Field and Pinedale Anticline areas. During 2002, we expect to participate in the drilling of 28 gross wells, or approximately 3 net wells on the Pinedale Anticline. The expected drilling and completion costs per gross well are approximately $3.0 million to $4.0 million and the average well depth in this area approximates 13,000 feet. Our average finding and development costs are estimated to be $0.70 to $0.90 per Mcf. We had established proven developed and undeveloped reserves totaling 71 Bcfe at December 31, 2001. This represents a 29% increase as compared to December 31, 2000. As of December 31, 2001, we estimate a net total of 101 Bcf of probable and possible reserves associated with undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves.

Gas. We market gas produced at our wells and our plants and purchased from third parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. Historically, our gas marketing was an outgrowth of our gas processing activities and was directed towards selling gas processed at our plants to ensure their efficient operation. As the natural gas industry became deregulated and offered more opportunity, we began to increase our third-party gas marketing. For the quarter and six months ended June 30, 2002, our total gas sales volumes averaged 1.9 BcfD and 2.2 BcfD, respectively. Third-party sales, firm transportation capacity on market pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods. We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. The duration of

our sales contracts have an average tenor of 17 months. In addition to our offices in Denver and Houston, we have a marketing office in Calgary, Alberta. The Calgary office also provides us with information regarding market conditions in Canada, which affect the gas markets in the United States.

Our 2002 gas marketing plan emphasizes growth through our asset base and storage and transportation capacities that we control. In general, we do not expect to increase our third-party sales volumes in 2002 significantly from levels achieved over the last several years, and, in fact, due to credit concerns in the energy industry, our overall sales volumes may decrease in the second half of this year. We continually monitor and review the credit exposure to our marketing counter parties. As the probable failure of Enron became more apparent in the third quarter of 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. If any of these customers with whom we have netting agreements were to file for bankruptcy, although similar netting agreements have been upheld by bankruptcy courts in the past, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge. Primarily due to the bankruptcy filing of a large mid-western co-op in this quarter, we incurred a charge to income through an allowance for doubtful accounts of $1.6 million in the second quarter of 2002.

We have identified one Master Swap Agreement containing ratings triggers. Under this agreement, we may be required to post additional collateral in the event of a decrease in our current rating by Standard & Poor's or Moody's Investors Service. Based on our outstanding positions under this agreement at June 30, 2002, if a ratings downgrade had occurred on that date, we would not have been required to post any collateral.

On June 5, 2002, and as amended on June 18, 2002, we responded to a data request of the Federal Energy Regulatory Commission (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 the time period described above, we engaged in two transactions that met the FERC's criteria for a trading 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 trading volume or revenue. Our internal control policies require valuation of the current market value of gas placed in storage based upon some objective criteria, and these transactions were intended to provide a third-party generated price for natural gas placed in storage. These transactions represent 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. During the first six months of 2002, no transactions of this type are included in our revenues.

NGLs. We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third parties, in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. For the quarter and six months ended June 30, 2002, NGL sales averaged 2,125 MGal per day and 2,035 MGal per day, respectively.

Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products. Over the last several years, the petrochemical industry has increased its use of NGLs as a major feedstock and is projected to continue to increase such usage. Further, consumers use propane for home heating, transportation and for agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

We decreased NGL sales to third parties by approximately 245 MGal per day and 265 MGal per day, for the quarter and six months ended June 30, 2002, respectively, compared to the same periods in 2001. These decreases were due to an overall reduction in the margin available on NGL transactions and due to credit concerns with our customers in the NGL industry. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counter parties. Upon the sale of our Toca facility, which is currently expected to close in the third quarter of 2002, we anticipate that sales of third party product will decrease beginning in the fourth quarter of 2002.

We own and operate MIGC, an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, an intrastate pipeline located in northeast Wyoming. MIGC charges a FERC approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC. During the first six months of 2002, MIGC transported an average of 180 MMcf per day. It is anticipated that MIGC will continue at that level for the next several years. MGTC provides transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and Wright at rates that are subject to the approval of the Wyoming Public Service Commission.

The FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies. In addition, the FERC has proposed to limit the use of affiliates' employees in the operation of regulated entities. On August 1, 2002, the FERC issued a Notice of Proposed Rule Making that, if enacted, would require MIGC to establish its own cash management function possibly including its own revolving credit facility. In addition, this proposed rule would limit the ability of MIGC to transfer funds to its parent company. Further, this proposed rule would require us to modify our existing subsidiary guarantees under our credit facilities. 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.

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 April 30, 2004. At June 30, 2002, $108.5 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 June 30, 2002, the interest rate payable on borrowings under this facility was approximately 2.9%. 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. The ratio must exceed 2.5 to 1.0

through September 30, 2002 and increases to 3.25 to 1.0 at December 31, 2002. This facility is guaranteed and secured via a pledge of the stock of all of our material subsidiaries.

Master Shelf Agreement. In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at June 30, 2002 are as indicated in the following table (dollars in thousands):

Under our agreement with Prudential, we are required to maintain a current ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not more than 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 some non-recurring items. In addition, this agreement contains a calculation limiting dividends. Under this limitation, approximately $80.5 million was available to be paid at June 30, 2002. This facility also limits our ability to enter into operating leases and sale leaseback transactions. We are currently paying an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee will continue until we receive an implied investment grade rating on our senior unsecured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed by, and secured via, a pledge of the stock of all of our material subsidiaries.

In October 2002, we expect to make a required principal repayment under the Master Shelf Agreement of $8.3 million with funds available under the Revolving Credit Facility.

Senior Subordinated Notes. In 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradeable notes under the same terms and conditions. The 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, approximately $50.4 million was available at June 30, 2002. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by all of our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which have been capitalized and will be amortized over the term of the notes.

Covenant Compliance. We were in compliance with all covenants in our debt agreements at June 30, 2002. Taking into account all the covenants contained in these agreements, we had approximately $88 million of available borrowing capacity at June 30, 2002. None of our credit facilities include covenant requirements or acceleration provisions based upon a change in our credit ratings.

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

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

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

We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counter parties and have agreements with many of these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked-to-market daily for the credit review process. Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counter parties based upon the mark-to-market value of their net exposure. We are subject to margin deposit requirements under these same agreements. In addition, we are subject to similar margin deposit requirements for our NYMEX counter parties related to our net exposures.

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

Hedge Positions. For the remaining two quarters of 2002, we have hedged approximately 63% of our projected equity natural gas volumes and approximately 68% of our estimated equity production of crude oil, condensate, and NGLs. For 2003, we have entered into hedging positions for approximately 25% of our projected equity gas volumes. 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 the six months ended June 30, 2002, we recognized a total of $132,000 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 and no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges.

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.

Outstanding Equity Hedges for the remainder of 2002. All prices are NYMEX-equivalents and do not include the cost of NGL hedges in 2002 of approximately $3 million.

		3rd and 4th Quarters of 2002
Natural gas		80,000 MMbtu per day with an average minimum and maximum price of $3.81 and $5.87 per MMbtu, respectively.
Crude, Condensate, Natural Gasoline and Butanes		75,000 Barrels per month. Fixed price of $20.20 per barrel with right to participate in price increases above $22.50 per barrel.
		55,000 Barrels per month. Floor at $20.00 per barrel.
Propane		120,000 Barrels per month. Floor at $0.32 per gallon.
Ethane		50,000 Barrels per month. Floor at $0.21 per gallon.
		20,000 Barrels per month. Sold at $0.21 per gallon with right to participate in price increases above $0.25 per gallon.

Account balances related to equity hedging transactions at June 30, 2002, were $13.2 million in Current Assets from price risk management activities, $400,000 in Non-current Assets from price risk management activities, $4.8 million in Current Liabilities from price risk management activities, $600,000 in Liabilities from price risk management activities, $3.0 million in Deferred income taxes payable, net and a $5.2 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Shareholder's Equity. Based on the commodity prices as of June 30, 2002, an after-tax gain of $5.3 million would be re-classified from Accumulated other comprehensive income to Product Purchases during the next twelve months.

Summary of Derivative Positions. A summary of the change in our derivative position from December 31, 2001 to June 30, 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		(6,522	)
Increase in value due to new contracts entered into during the period		22,403
Gains realized during the period from existing and new contracts		(36,499	)
Changes in fair value attributable to changes in valuation techniques		—

Fair value of contracts outstanding at June 30, 2002	$	28,793

A summary of our outstanding derivative positions at June 30, 2002 is as follows (dollars in thousands):

	Fair Value of Contracts at June 30, 2002
Source of Fair Value	Total Fair Value		Maturing In 2002		Maturing In 2003-2004		Maturing In 2005-2006		Maturing Thereafter
Exchange published prices	$	(9,953	)	$	(3,676	)	$	(6,277	)		—		—
Other actively quoted prices (1)		28,274			18,114			10,274		$	(114	)	—
Other valuation methods (2)		10,472			10,362			110			—		—

Total fair value	$	28,793		$	24,800		$	4,107		$	(114	)	—

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 June 30, 2002, the net notional value of such contracts was approximately $16.2 million in Canadian dollars, which approximates its fair market value.

Accounting for Derivative Instruments and Hedging Activities. In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities, which, for various reasons, are not designated or qualified as hedges under SFAS 133.

The following tables provide information concerning our principal facilities at June 30, 2002. We also own and operate several smaller treating, processing and transportation facilities located in the same areas as our other facilities.

Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver County, Colorado, Civil Action No. 00-CV-1433. We were 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 our results of operations or financial position. We are seeking reimbursement from Amerada Hess under a contractual indemnity. We amended our 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 us in this matter. On May 31, 2002, we 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. At this time, we are unable to quantify the outcome of this appeal.

Texas Natural Resource Conservation Commission (TNRCC)—Notification of Alleged Violations, Midkiff, Texas. We have received notification of six alleged violations associated with our air emissions permit at the Midkiff Gas Plant in Texas. Five of the alleged violations relate to reporting requirements under the permit and one alleged violation relates to the failure to operate within the time restrictions of the permit. We have responded to the TNRCC and are taking corrective action. On July 17, 2002 we entered into an Agreed Order with the TNRCC resolving the alleged violations, which included a total payment of $25,000 for administrative penalties.

Texas Natural Resource Conservation Commission—Notification of Alleged Violations, Gomez Treating Plant, Texas. We have received notification of an alleged violation associated with compliance certifications for a Gomez Treating Plant owned by an unaffiliated company, which subsequently sold the Gomez Compressor Station to us in 1999. We have contested the alleged violation on the basis that we never purchased this treating facility and the unaffiliated company had physically removed the facility in 1995. At this time, we are unable to quantify penalties or fines, if any, associated with this alleged violation.

Texas Natural Resource Conservation Commission—Notification of Alleged Violations, Gomez Treating Plant, Texas. On July 12, 2002, we received notification of three alleged violations associated with failure to provide information related to upset and maintenance reports. Since notification, we have re-submitted reports based upon the recommended action of the TNRCC. At this time, we are unable to quantify penalties or fines, if any, associated with the alleged violations.

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

The following matters were voted on at our Annual Meeting of Stockholders held on May 17, 2002:

Brion G. Wise, Richard B. Robinson and Peter A. Dea were elected as Class One Directors to serve until their terms expire in 2005 and until their successors have been elected. A total of 25,731,810, 25,617,198 and 25,723,333 shares, respectively, were voted for and 758,969, 873,581and 767,447 shares, respectively, were withheld for Brion G. Wise, Richard B. Robinson and Peter A. Dea. There were no broker non-votes or abstentions.

Joseph E. Reid, Ward Sauvage and Lanny F. Outlaw will continue to serve as Class Two Directors until their terms expire in 2003, and until their successors have been elected.

Bill M. Sanderson, Dean Phillips, Walter L. Stonehocker and James A. Senty will continue to serve as Class Three Directors until their terms expire in 2004, and until their successors have been elected.

The 2002 Non-Employee Director Stock Option Plan was approved. A total of 22,742,078 shares were voted for and 3,685,737 shares were withheld for the 2002 Non-Employee Director Stock Option Plan. Broker non-votes totaled 0 and abstentions totaled 62,964.

The 2002 Stock Incentive Plan was approved. A total of 25,055,538 shares were voted for and 1,359,469 shares were withheld for the 2002 Stock Incentive Plan. Broker non-votes totaled 0 and abstentions totaled 75,772.

99.1

Certification by Chief Executive Officer and Chief Financial Officer required by Sarbanes-Oxley Act of 2002.

Pursuant to the requirements 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.


PART I—Financial Information
	Item 1.	Financial Statements
		Consolidated Balance Sheet—June 30, 2002 and December 31, 2001
		Consolidated Statement of Cash Flows—Six Months Ended June 30, 2002 and 2001
		Consolidated Statement of Operations—Three and Six Months Ended June 30, 2002 and 2001
		Consolidated Statement of Changes in Stockholders' Equity—Six Months Ended June 30, 2002
		Notes to Consolidated Financial Statements
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk
PART II—Other Information
	Item 1.	Legal Proceedings
	Item 4.	Submission of Matters to a Vote of Security Holders
	Item 6.	Exhibits and Reports on Form 8-K
Signatures

			June 30, 2002			December 31, 2001
			(unaudited)
		ASSETS
Current assets:
	Cash and cash equivalents		$	27,728		$	10,032
	Trade accounts receivable, net			236,247			231,724
	Product inventory			37,442			50,773
	Parts inventory			43			3,049
	Assets from price risk management activities			44,719			66,271
	Assets held for sale			35,483			—
	Other			1,897			4,114

		Total current assets		383,559			365,963
Property and equipment:
	Gas gathering, processing and transportation			891,581			912,003
	Oil and gas properties and equipment (successful efforts method)			216,576			193,656
	Construction in progress			107,803			106,385

				1,215,960			1,212,044
Less: Accumulated depreciation, depletion and amortization				(376,467	)		(363,737	)

		Total property and equipment, net		839,493			848,307

Other assets:
	Gas purchase contracts (net of accumulated amortization of $36,281 and $35,329, respectively)			31,875			32,826
	Assets from price risk management activities			2,340			2,934
	Other			24,697			17,912

	Total other assets			58,912			53,672

Total assets			$	1,281,964		$	1,267,942

		LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	239,309		$	260,208
	Accrued expenses			36,709			23,123
	Liabilities from price risk management activities			16,004			18,075
	Dividends payable			3,780			3,767

		Total current liabilities		295,802			305,173
Long-term debt				381,567			366,667
Liabilities from price risk management activities				2,262			1,720
Other long-term liabilities				1,999			2,284
Deferred income taxes payable, net				117,279			118,746

Total liabilities				798,909			794,590
Stockholders' equity:
	Preferred Stock; 10,000,000 shares authorized:
		$2.28 cumulative preferred stock, par value $.10; 591,136 issued and outstanding, ($15,885,650 aggregate liquidation preference)		59			59
		$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued and outstanding ($138,000,000 aggregate liquidation preference)		276			276
	Common stock, par value $.10; 100,000,000 shares authorized; 33,000,457 and 32,689,009 shares issued, respectively			3,324			3,293
	Treasury stock, at cost; 25,016 common shares and 44,290 $2.28 cumulative preferred shares in treasury			(1,907	)		(1,907	)
	Additional paid-in capital			393,818			387,505
	Retained earnings			80,335			66,128
	Accumulated other comprehensive income			7,739			18,882
	Notes receivable from key employees secured by common stock			(589	)		(884	)

		Total stockholders' equity		483,055			473,352

Total liabilities and stockholders' equity			$	1,281,964		$	1,267,942

		Six Months Ended June 30,
		2002			2001
Reconciliation of net income to net cash provided by operating activities:
Net income		$	21,766		$	70,043
Add income items that do not affect cash:
	Depreciation, depletion and amortization		35,189			29,761
	(Gain) loss on the sale of property and equipment		82			(11,223	)
	Deferred income taxes		7,855			27,897
	Non-cash change in fair value of derivatives		3,129			(2,176	)
	Other non-cash items, net		1,912			483

			69,933			114,785
Adjustments to working capital to arrive at net cash provided by operating activities:
	(Increase) decrease in trade accounts receivable		(6,812	)		263,435
	(Increase) decrease in product inventory		13,331			(22,851	)
	Decrease in parts inventory		—			429
	(Increase) decrease in other current assets		(473	)		477
	(Increase) decrease in other assets and liabilities, net		425			(75	)
	Decrease in accounts payable		(20,899	)		(236,750	)
	Increase in accrued expenses		12,733			18,848

Net cash provided by operating activities			68,238			138,298

Cash flows from investing activities:
	Purchases of property and equipment		(57,855	)		(74,539	)
	Proceeds from the dispositions of property and equipment		465			38,075
	Contributions to equity investees		(6,583	)		(637	)

Net cash used in investing activities			(63,973	)		(37,101	)

Cash flows from financing activities:
	Net proceeds from exercise of common stock options		6,191			4,623
	Repurchase of $2.28 cumulative preferred stock		—			(129	)
	Debt issue costs paid		(114	)		(91	)
	Payments on revolving credit facility		(522,100	)		(344,900	)
	Borrowings under revolving credit facility		537,000			291,200
	Dividends paid		(7,546	)		(8,413	)

Net cash provided by (used in) financing activities			13,431			(57,710	)

Net increase in cash and cash equivalents			17,696			43,487
Cash and cash equivalents at beginning of period			10,032			12,927

Cash and cash equivalents at end of period		$	27,728		$	56,414

			Three Months Ended June 30,						Six Months Ended June 30,
			2002			2001			2002			2001
Revenues:
	Sale of residue gas		$	510,198		$	757,998		$	1,055,787		$	1,804,590
	Sale of natural gas liquids			79,866			114,492			144,674			243,969
	Processing and transportation revenue			15,028			16,304			30,459			30,624
	Unrealized gain (loss) on marketing activities			7,866			(2,873	)		(3,129	)		2,176
	Other, net			1,972			1,103			3,905			2,941

		Total revenues		614,930			887,024			1,231,696			2,084,300

Costs and expenses:
	Product purchases			528,289			784,550			1,072,895			1,871,150
	Plant operating expense			19,790			18,240			38,661			35,277
	Oil and gas exploration and production expense			9,142			9,098			16,531			18,703
	Depreciation, depletion and amortization			17,243			15,283			35,189			29,761
	(Gain) loss on sale of assets			73			—			82			(11,223	)
	Selling and administrative expense			11,887			7,545			20,578			16,024
	Interest expense			6,770			5,992			13,430			12,821

		Total costs and expenses		593,194			840,708			1,197,366			1,972,513

Income before income taxes				21,736			46,316			34,330			111,787
Provision for income taxes:
	Current			3,951			5,685			4,709			13,847
	Deferred			4,019			11,178			7,855			27,897

		Total provision for income taxes		7,970			16,863			12,564			41,744

Net income				13,766			29,453			21,766			70,043
Preferred stock requirements				(2,130	)		(2,584	)		(4,260	)		(5,169	)

Income attributable to common stock			$	11,636		$	26,869		$	17,506		$	64,874

Earnings per share of common stock			$	.35		$	.82		$	.53		$	2.00

Weighted average shares of common stock outstanding				32,994,543			32,579,509			32,877,312			32,492,276

Income attributable to common stock—fully diluted			$	11,636		$	28,680		$	17,506		$	68,497

Earnings per share of common stock—fully diluted			$	.34		$	.77		$	.52		$	1.85

Weighted average shares of common stock outstanding—fully diluted				33,779,869			37,073,854			33,621,877			36,965,284

	Gas Gathering and Processing		Production			Marketing		Transportation		Corporate			Eliminating Entries			Total
Quarter ended June 30, 2002
Revenues from unaffiliated customers	$	14,622	$	(1,439	)	$	587,061	$	3,221	$	106		$	—		$	603,571
Interest income		—		14			10		—		2,068			(2,026	)		66
Equity hedges		—		—			—		—		2,959			—			2,959
Other, net		312		36			7,510		2		474			—			8,334
Inter-segment sales		160,825		27,926			5,866		3,728		13			(198,358	)		—

Total revenues		175,759		26,537			600,447		6,951		5,620			(200,384	)		614,930

Product purchases		131,632		1,904			586,088		—		(154	)		(191,181	)		528,289
Plant operating expense		17,264		133			132		2,834		(234	)		(339	)		19,790
Oil and gas exploration and production expense		—		15,536			—		—		—			(6,394	)		9,142

Operating profit	$	26,863	$	8,964		$	14,227	$	4,117	$	6,008		$	(2,470	)	$	57,709

Depreciation, depletion and amortization		11,223		3,923			40		425		1,632			—			17,243
Interest expense																	6,770
Loss on sale of assets																	73
Selling and administrative expense																	11,887

Income before income taxes																$	21,736

Identifiable assets	$	578,230	$	207,378		$	78	$	46,172	$	57,922		$	—		$	889,780

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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

			Shares of $2.28 Cumulative Preferred Stock	Shares of $2.28 Cumulative Preferred Stock in Treasury	$2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	$2.28 Cumulative Preferred Stock		$2.625 Cumulative Convertible Preferred Stock		Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income Net of Tax			Notes Receivable from Key Employees			Total Stockholders' Equity
Balance at December 31, 2001			591,136	44,290	2,760,000	32,689,009	25,016	$	59	$	276	$	3,293	$	(1,907	)	$	387,505	$	66,128		$	18,882		$	(884	)	$	473,352
Comprehensive income:
	Net income, six months ended June 30, 2002		—	—	—	—	—		—		—		—		—			—		21,766			—			—			21,766
	Translation adjustments		—	—	—	—	—		—		—		—		—			—		—			794			—			794
	Reclassification adjustment for settled contracts		—	—	—	—	—		—		—		—		—			—		—			(8,940	)		—			(8,940	)
	Changes in fair value of outstanding hedging positions		—	—	—	—	—		—		—		—		—			—		—			(2,817	)		—			(2,817	)
	Reduction due to estimated ineffectiveness		—	—	—	—	—		—		—		—		—			—		—			(27	)		—			(27	)
	Fair value of new hedge positions		—	—	—	—	—		—		—		—		—			—		—			(153	)					(153	)

		Change in accumulated derivative comprehensive income	—	—	—	—	—		—		—		—		—			—		—			(11,937	)		—			(11,937	)

	Total comprehensive income, net of tax																												7,739

Stock options exercised			—	—	—	311,448	—		—		—		31		—			5,865		—			—			—			5,896
Effect of re-priced stock options			—	—	—	—	—		—		—		—		—			448		—			—			—			448
Loans forgiven			—	—	—	—	—		—		—		—		—			—		—			—			295			295
Dividends declared on common stock			—	—	—	—	—		—		—		—		—			—		(3,299	)		—			—			(3,299	)
Dividends declared on $2.28 cumulative preferred stock			—	—	—	—	—		—		—		—		—			—		(638	)		—			—			(638	)
Dividends declared on $2.625 cumulative convertible preferred stock			—	—	—	—	—		—		—		—		—			—		(3,622	)		—			—			(3,622	)
Repurchase of $2.28 cumulative preferred stock			—	—	—	—	—		—		—		—		—			—		—			—			—			—

Balance at June 30, 2002			591,136	44,290	2,760,000	33,000,457	25,016	$	59	$	276	$	3,324	$	(1,907	)	$	393,818	$	80,335		$	7,739		$	(589	)	$	483,055

	Gas Gathering and Processing		Production		Marketing			Transportation		Corporate			Eliminating Entries			Total
Quarter ended June 30, 2001
Revenues from unaffiliated customers	$	16,165	$	107	$	871,397		$	2,309	$	21		$	—		$	889,999
Interest income		1		1		—			—		3,373			(3,017	)		358
Equity hedges		—		—		—			—		(1,708	)		—			(1,708	)
Other, net		—		—		(2,701	)		—		1,076			—			(1,625	)
Inter-segment sales		219,730		29,417		9,125			4,391		13			(262,676	)		—

Total revenues		235,896		29,525		877,821			6,700		2,775			(265,693	)		887,024

Product purchases		182,904		1,964		859,515			434		122			(260,389	)		784,550
Plant operating expense		16,952		68		80			1,738		(449	)		(149	)		18,240
Oil and gas exploration and production expense		—		10,591		—			—		—			(1,493	)		9,098

Operating profit	$	36,040	$	16,902	$	18,226		$	4,528	$	3,102		$	(3,662	)	$	75,136

Depreciation, depletion and amortization		9,461		3,845		40			419		1,518			—			15,283
Interest expense																	5,992
Gain on sale of assets																	—
Selling and administrative expense																	7,545

Income (loss) before income taxes																$	46,316

Identifiable assets	$	581,874	$	158,517	$	81		$	47,796	$	57,015		$	—		$	845,283

	Gas Gathering and Processing		Production			Marketing			Transportation		Corporate			Eliminating Entries			Total
Six months ended June 30, 2002
Revenues from unaffiliated customers	$	29,073	$	(130	)	$	1,185,768		$	6,225	$	122		$	—		$	1,221,058
Interest income		—		24			10			—		3,895			(3,826	)		103
Equity hedges		—		—			—			—		12,281			—			12,281
Other, net		664		19			(3,434	)		14		991			—			(1,746	)
Inter-segment sales		281,940		48,910			9,426			7,857		27			(348,160	)		—

Total revenues		311,677		48,823			1,191,770			14,096		17,316			(351,986	)		1,231,696

Product purchases		232,824		3,604			1,170,158			—		168			(333,859	)		1,072,895
Plant operating expense		33,796		133			132			5,449		(2	)		(847	)		38,661
Oil and gas exploration and production expense		—		28,581			—			—		—			(12,050	)		16,531

Operating profit	$	45,057	$	16,505		$	21,480		$	8,647	$	17,150		$	(5,230	)	$	103,609

Depreciation, depletion and amortization		21,498		9,566			80			860		3,185			—			35,189
Interest expense																		13,430
Loss on sale of assets																		82
Selling and administrative expense																		20,578

Income before income taxes																	$	34,330

Identifiable assets	$	578,230	$	207,378		$	78		$	46,172	$	57,922		$	—		$	889,780

	Gas Gathering and Processing		Production			Marketing		Transportation		Corporate			Eliminating Entries			Total
Six months ended June 30, 2001
Revenues from unaffiliated customers	$	30,200	$	828		$	2,058,653	$	4,984	$	303		$	—		$	2,094,968
Interest income		1		1			—		—		8,459			(7,819	)		642
Equity hedges		—		—			—		—		(15,971	)		—			(15,971	)
Other, net		4		(1	)		2,203		2		2,453			—			4,661
Inter-segment sales		537,803		81,567			20,611		8,658		27			(648,666	)		—

Total revenues		568,008		82,395			2,081,467		13,644		(4,729	)		(656,485	)		2,084,300

Product purchases		455,743		4,609			2,047,680		—		135			(637,017	)		1,871,150
Plant operating expense		32,272		98			119		3,832		(74	)		(970	)		35,277
Oil and gas exploration and production expense		—		27,645			—		—		—			(8,942	)		18,703

Operating profit	$	79,993	$	50,043		$	33,668	$	9,812	$	(4,790	)	$	(9,556	)	$	159,170

Depreciation, depletion and amortization		18,961		6,912			80		834		2,974			—			29,761
Interest expense																	12,821
Gain on sale of assets																	(11,223	)
Selling and administrative expense																	16,024

Income (loss) before income taxes																$	111,787

Identifiable assets	$	581,874	$	158,517		$	81	$	47,796	$	57,015		$	—		$	845,283

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended June 30,				Percent Change		Six Months Ended June 30,				Percent Change
	2002		2001		Percent Change		2002		2001		Percent Change
Financial results:
Revenues	$	614,930	$	887,024	(31	)	$	1,231,696	$	2,084,300	(41	)
Gross profit		40,393		59,853	(33	)		68,338		140,632	(51	)
Net income		13,766		29,453	(53	)		21,766		70,043	(69	)
Income per share of common stock		.35		.82	(56	)		.53		2.00	(74	)
Income per share of common stock—fully diluted		.34		.77	(56	)		.52		1.85	(72	)
Cash provided by operating activities	$	45,713	$	31,754	44		$	68,238	$	138,298	(51	)
Operating data:
Average gas sales (MMcf/D)		1,855		1,835	1			2,150		1,755	23
Average NGL sales (MGal/D)		2,125		2,370	(10	)		2,035		2,300	(12	)
Average gas prices ($/Mcf)	$	3.07	$	4.53	(32	)	$	2.73	$	5.68	(52	)
Average NGL prices ($/Gal)	$	.41	$	.53	(23	)	$	.39	$	.58	(33	)

			Payments by Period
Type of Obligation	Total Obligation		Due in 2002		Due in 2003—2004		Due in 2005—2006		Due Thereafter
Long-term Debt	$	381,567	$	8,333	$	188,234	$	20,000	$	165,000
Guarantee of Fort Union Project Financing		6,654		355		1,556		1,795		2,948
Operating Leases		60,424		4,274		13,043		12,125		30,982
Firm Transportation Capacity Agreements		231,957		29,306		46,937		45,719		109,995
Firm Storage Capacity Agreements		26,566		4,623		4,632		3,657		13,654

Total Contractual Cash Obligations	$	707,168	$	46,891	$	254,402	$	83,296	$	322,579

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

	$	116,666

Natural gas		20,000 MMbtu per day at an average price of $3.75 per MMbtu.
		20,000 MMbtu per day with a minimum price of $3.50 and an average maximum price of $4.43 per MMbtu.

						Average for the Six Months Ended June 30, 2002
				Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcf/D)(3)	Average for the Six Months Ended June 30, 2002
Facilities(1)			Year Placed In Service	Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcf/D)(3)	Gas Throughput (MMcf/D)(4)	Gas Production (MMcf/D)(5)	NGL Production (MGal/D)(5)
*Texas*
	Gomez Treating(6)		1971	386	280	94	85	—
	Midkiff/Benedum		1949	2,213	165	142	95	869
	Mitchell Puckett Gathering(6)		1972	93	120	52	34	1
*Louisiana*
	Toca(7)(8)		1958	—	160	77	72	60
*Wyoming*
	Coal Bed Methane Gathering		1990	1,253	223	351	190	—
	Fort Union Gas Gathering		1999	106	635	429	429	—
	Granger(7)(9)(10)		1987	524	235	160	147	260
	Hilight Complex(7)		1969	626	124	15	50	11
	Kitty/Amos Draw(7)		1969	314	17	8	5	31
	Lincoln Road(10)		1988	149	50	19	18	8
	Newcastle(7)		1981	146	5	3	2	18
	Red Desert(7)		1979	111	42	13	11	23
	Rendezvous Gas Services		2001		125	93	93	—
	Reno Junction(9)		1991	—	—	—	—	102
*Oklahoma*
	Chaney Dell		1966	2,082	130	145	126	209
	Westana		1981	1,001	45	78	73	16
*New Mexico*
	San Juan River(6)		1955	140	60	24	19	19
*Utah*
	Four Corners Gathering		1988	104	15	2	2	10

		Total		9,248	2,431	1,705	1,451	1,637

				Average for the Six Months Ended June 30, 2002
Transportation Facilities(1)		Year Placed In Service	Transportation Miles(2)	Pipeline Capacity (MMcfD)(2)	Gas Throughput (MMcfD)(4)
MIGC(11)(13)		1970	245	130	180
MGTC(12)		1963	252	18	12

	Total		497	148	192

	WESTERN GAS RESOURCES, INC. (Registrant)
Date: August 13, 2002	By:	/s/ PETER A. DEA Peter A. Dea Chief Executive Officer and President
Date: August 13, 2002	By:	/s/ WILLIAM J. KRYSIAK William J. Krysiak Chief Financial Officer (Principal Financial and Accounting Officer)