<PAGE>

                      SECURITIES AND EXCHANGE COMMISSION
                      ----------------------------------
                            Washington, D.C. 20549
                            ----------------------

                                   FORM 10-Q
(Mark One)
----------

[X]    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
       EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001 OR

[_]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
       EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _________________
       TO _________________


                        Commission file number 1-10389
                        ------------------------------


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


                  Delaware                                 84-1127613
--------------------------------------------     -------------------------------
      (State or other jurisdiction of                   (I.R.S. Employer
      incorporation or organization)                   Identification No.)

   12200 N. Pecos Street, Denver, Colorado                   80234-3439
--------------------------------------------------------------------------------
  (Address of principal executive offices)                   (Zip Code)

                                 (303) 452-5603
--------------------------------------------------------------------------------
               Registrant's telephone number, including area 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 X  No
                                      ---

On August 1, 2001, there were 32,653,000 shares of the registrant's Common Stock
outstanding.

                                       1
<PAGE>

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


<TABLE>
<CAPTION>
PART I - Financial Information                                                                                          Page
------------------------------                                                                                          ----
<S>                                                                                                                     <C>
     Item 1.    Financial Statements


                Consolidated Balance Sheet - June 30, 2001 and December 31, 2000.....................................    3

                Consolidated Statement of Cash Flows - Three and Six Months Ended
                June 30, 2001 and 2000...............................................................................    4

                Consolidated Statement of Operations - Three and Six Months Ended
                June 30, 2001 and 2000...............................................................................    5

                Consolidated Statement of Changes in Stockholders' Equity - Six Months Ended
                June 30, 2001........................................................................................    6

                Notes to Consolidated Financial Statements...........................................................    7

     Item 2.    Management's Discussion and Analysis of Financial Condition and Results of
                Operations...........................................................................................   12

     Item 3.    Quantitative and Qualitative Disclosures about Market Risk...........................................   20

PART II - Other Information
---------------------------

     Item 1.    Legal Proceedings....................................................................................   24

     Item 4.    Submission of matters to a vote of security holders..................................................   25

     Item 6.    Exhibits and Reports on Form 8-K.....................................................................   25

Signatures...........................................................................................................   26
</TABLE>

                                       2
<PAGE>

PART I - FINANCIAL INFORMATION

Item 1.     Financial Statements
            --------------------

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

<TABLE>
<CAPTION>
                                                                                                      June 30,       December 31,
       ASSETS                                                                                           2001             2000
       ------                                                                                        ---------        ----------
                                                                                                     (unaudited)
<S>                                                                                                 <C>             <C>
Current assets:
   Cash and cash equivalents...................................................................     $    56,414     $      12,927
   Trade accounts receivable, net..............................................................         276,079           546,791
   Product inventory...........................................................................          67,673            44,822
   Parts inventory.............................................................................           3,060             3,489
   Assets from price risk management activities................................................          54,831                 -
   Assets held for sale........................................................................               -            25,001
   Other ......................................................................................           2,177             2,654
                                                                                                    -----------     -------------
      Total current assets.....................................................................         460,234           635,684

Property and equipment:
   Gas gathering, processing, storage and transportation.......................................         884,076           856,982
   Oil and gas properties and equipment (successful efforts method)............................         168,889           139,084
   Construction in progress....................................................................          76,577            58,319
                                                                                                    -----------     -------------
                                                                                                      1,129,542         1,054,385
 Less: Accumulated depreciation, depletion and amortization....................................        (333,781)         (306,651)
                                                                                                    -----------     --------------
      Total property and equipment, net........................................................         795,761           747,734
                                                                                                    -----------     -------------
Other assets:
   Gas purchase contracts (net of accumulated amortization of $34,336 and $33,357,
    respectively)..............................................................................          33,819            34,798
   Assets from price risk management activities................................................          13,333                 -
   Other ......................................................................................          13,492            13,206
                                                                                                    -----------     -------------
   Total other assets..........................................................................          60,644            48,004
                                                                                                    -----------     -------------
Total assets...................................................................................     $ 1,316,639     $   1,431,422
                                                                                                    ===========     =============
       LIABILITIES AND STOCKHOLDERS' EQUITY
       ------------------------------------
Current liabilities:
   Accounts payable............................................................................     $   344,813     $     581,563
   Accrued expenses............................................................................          43,027            25,094
   Liabilities from price risk management activities...........................................          26,488                 -
   Dividends payable...........................................................................           4,217             4,205
                                                                                                    -----------     -------------
      Total current liabilities................................................................         418,545           610,862
Long-term debt.................................................................................         305,000           358,700
Liabilities from price risk management activities..............................................           1,722                 -
Other long-term liabilities....................................................................           2,570             2,646
Deferred income taxes payable, net.............................................................         108,657            67,680
                                                                                                    -----------     -------------
Total liabilities..............................................................................         836,494         1,039,888
                                                                                                    -----------     -------------
Stockholders' equity:
   Preferred Stock; 10,000,000 shares authorized:
      $2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued
          ($35,000,000 aggregate liquidation preference).......................................             140               140
      $2.625 cumulative convertible preferred stock, par value $.10; 2,760,000
         issued ($138,000,000 aggregate liquidation preference)................................             276               276
   Common stock, par value $.10; 100,000,000 shares authorized; 32,652,057 and
         32,361,131 shares issued, respectively ...............................................           3,289             3,265
   Treasury stock, at cost; 25,016 common shares and 44,290 $2.28 cumulative
         preferred shares in treasury..........................................................          (1,907)           (1,778)
   Additional paid-in capital..................................................................         404,756           400,157
   Retained earnings (deficit).................................................................          49,798           (11,820)
   Accumulated other comprehensive income......................................................          24,677             2,178
   Notes receivable from key employees secured by common stock.................................            (884)             (884)
                                                                                                    -----------     -------------
      Total stockholders' equity...............................................................         480,145           391,534
                                                                                                    -----------     -------------
Total liabilities and stockholders' equity.....................................................     $ 1,316,639     $   1,431,422
                                                                                                    ===========     =============
</TABLE>

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

                                       3
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                                   Six Months Ended
                                                                                                       June 30,
                                                                                            ------------------------------
                                                                                                2001             2000
                                                                                            ------------     -------------
<S>                                                                                         <C>              <C>
Reconciliation of net income to net cash provided by operating activities:
Net income .........................................................................        $     70,043      $     23,586
Add income items that do not affect cash:
  Depreciation, depletion and amortization..........................................              29,761            27,532
  Gain on the sale of property and equipment........................................             (11,223)           (5,634)
  Deferred income taxes.............................................................              27,897            13,262
  Other non-cash items, net.........................................................              (1,693)              880
                                                                                            ------------      ------------
                                                                                                 114,785            59,626
Adjustments to working capital to arrive at net cash provided by
  operating activities:
  (Increase) decrease in trade accounts receivable..................................             263,435          (136,174)
  (Increase) decrease in product inventory .........................................             (22,851)            3,026
  Decrease in parts inventory ......................................................                 429             1,259
  Decrease in other current assets..................................................                 477             6,305
  (Increase) decrease in other assets and liabilities, net..........................                 (75)                6
  Increase (decrease) in accounts payable...........................................            (236,750)           98,253
  Increase (decrease) in accrued expenses...........................................              18,848           (16,556)
                                                                                            ------------      ------------

Net cash provided by operating activities...........................................             138,298            15,745
                                                                                            ------------      ------------

Cash flows from investing activities:

  Purchases of property and equipment...............................................             (74,539)          (51,216)
  Proceeds from the dispositions of property and equipment .........................              38,075            15,916
  Contributions to equity investees.................................................                (637)                -
                                                                                            ------------      ------------

Net cash used in investing activities...............................................             (37,101)          (35,300)
                                                                                            ------------      ------------

Cash flows from financing activities:

  Net proceeds from exercise of common stock options................................               4,623               259
  Repurchase of $2.28 cumulative preferred stock....................................                (129)                -
  Debt issue costs paid.............................................................                 (91)               (5)
  Payments on revolving credit facility.............................................            (344,900)         (608,136)
  Borrowings under revolving credit facility........................................             291,200           632,386
  Dividends paid....................................................................              (8,413)           (8,439)
                                                                                            ------------      ------------

Net cash provided by financing activities...........................................             (57,710)           16,065
                                                                                            ------------      ------------
Net increase (decrease) in cash and cash equivalents................................              43,487            (3,490)

Cash and cash equivalents at beginning of period....................................              12,927            14,062
                                                                                            ------------      ------------
Cash and cash equivalents at end of period .........................................        $     56,414      $     10,572
                                                                                            ============      ============
</TABLE>


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

                                       4
<PAGE>

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

<TABLE>
<CAPTION>
                                                                       Three Months Ended            Six Months Ended
                                                                            June 30,                     June 30,
                                                                   --------------------------   ---------------------------
                                                                       2001          2000           2001           2000
                                                                   -----------   ------------   ------------   ------------
<S>                                                               <C>            <C>            <C>            <C>
Revenues:
  Sale of residue gas..........................................   $    756,526   $    506,793   $  1,801,402   $    919,673
  Sale of natural gas liquids..................................        114,492        122,219        243,969        257,607
  Processing, transportation and storage revenue...............         16,304          9,410         30,624         23,295
  Unrealized gain (loss) on marketing activities...............         (2,873)             -          2,176              -
  Other, net...................................................          2,575          3,394          6,129          6,393
                                                                  ------------   ------------   ------------   ------------

      Total revenues...........................................        887,024        641,816      2,084,300      1,206,968
                                                                  ------------   ------------   ------------   ------------

Costs and expenses:
  Product purchases............................................        784,550        576,727      1,871,150      1,077,870
  Plant operating expense......................................         18,240         17,100         35,277         32,362
  Oil and gas exploration and production expense...............          9,098          1,791         18,703          5,937
  Depreciation, depletion and amortization ....................         15,283         14,223         29,761         27,532
  Gain on sale of assets ......................................              -           (335)       (11,223)        (5,634)
  Selling and administrative expense...........................          7,545          8,100         16,024         15,489
  Interest expense.............................................          5,992          7,809         12,821         16,027
                                                                  ------------   ------------   ------------   ------------

      Total costs and expenses.................................        840,708        625,415      1,972,513      1,169,583
                                                                  ------------   ------------   ------------   ------------

Income before income taxes.....................................         46,316         16,401        111,787         37,385

Provision for income taxes:
  Current .....................................................          5,685              -         13,847            537
  Deferred.....................................................         11,178          5,821         27,897         13,262
                                                                  ------------   ------------   ------------   ------------

      Total provision for income taxes.........................         16,863          5,821         41,744         13,799
                                                                  ------------   ------------   ------------   ------------

Net income.....................................................         29,453         10,580         70,043         23,586

Preferred stock requirements...................................         (2,584)        (2,610)        (5,169)        (5,220)
                                                                  -------------  ------------   ------------   ------------

Income attributable to common stock............................   $     26,869   $      7,970   $     64,874   $     18,366
                                                                  ============   ============   ============   ============

Earnings per share of common stock.............................   $        .82   $        .25   $       2.00   $        .57
                                                                  ============   ============   ============   ============

Weighted average shares of common stock outstanding............     32,579,509     32,196,793     32,492,276     32,181,331
                                                                  ============     ==========   ============   ============

Income attributable to common stock - fully diluted............   $     28,680   $     10,396   $     68,497   $     10,396
                                                                  ============   ============   ============   ============

Earnings per share of common stock -
  fully diluted................................................   $        .77   $        .24   $       1.85   $        .56
                                                                  ============   ============   ============   ============

Weighted average shares of common stock outstanding -
  fully diluted................................................     37,073,854     32,770,736     36,965,284     32,628,146
                                                                  ============   ============   ============   ============
</TABLE>


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

                                       5
<PAGE>

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

<TABLE>
<CAPTION>
                                                 Shares of       Shares of        $2.625
                                                   $2.28           $2.28        Cumulative                    Shares
                                                 Cumulative     Cumulative     Convertible    Shares        of Common
                                                 Preferred    Preferred Stock   Preferred    of Common        Stock
                                                   Stock        in Treasury       Stock        Stock       in Treasury
                                                 ----------   ---------------    --------   ----------     -----------
<S>                                                <C>              <C>        <C>          <C>               <C>
Balance at December 31, 2000...................    1,400,000        39,190      2,760,000     32,361,131        25,016
Comprehensive income:
  Net income, six months ended
    June 30, 2001..............................            -             -              -              -             -
    Cumulative effect of change in accounting
     principle - January 1, 2001...............            -             -              -              -             -
    Reclassification adjustment for settled
     contracts.................................            -             -              -              -             -
    Changes in fair value of outstanding
     hedging positions.........................            -             -              -              -             -
    Fair value of new hedge positions..........            -             -              -              -             -
     Ending accumulated derivative gain........            -             -              -              -             -
  Translation adjustments......................            -             -              -              -             -
  Total comprehensive income, net of tax.......

Stock options exercised........................            -             -              -        290,926             -
Tax benefit related to stock options...........            -             -              -              -             -
Loans forgiven.................................            -             -              -              -             -
Dividends declared on common stock.............            -             -              -              -             -
Dividends declared on $2.28 cumulative
  preferred stock..............................            -             -              -              -             -
Dividends declared on $2.625 cumulative
  convertible preferred stock..................            -             -              -              -             -
Repurchase of $2.28 cumulative
  preferred stock..............................            -         5,100              -              -             -
                                                  ----------    ----------     ----------    -----------    ----------
Balance at June 30, 2001.......................    1,400,000        44,290      2,760,000     32,652,057        25,016
                                                  ==========    ==========     ==========    ===========    ==========

<CAPTION>
                                                                      $2.625
                                                        $2.28       Cumulative
                                                      Cumulative   Convertible                              Additional
                                                      Preferred     Preferred       Common      Treasury     Paid-In
                                                        Stock         Stock         Stock         Stock      Capital
                                                     -----------   ------------   ----------   -----------   --------
<S>                                                <C>           <C>            <C>          <C>          <C>
Balance at December 31, 2000...................            140           276          3,265       (1,778)    400,157
Comprehensive income:
  Net income, six months ended
    June 30, 2001..............................              -             -              -            -           -
    Cumulative effect of change in accounting
     principle - January 1, 2001...............              -             -              -            -           -
    Reclassification adjustment for settled
     contracts.................................              -             -              -            -           -
    Changes in fair value of outstanding
     hedging positions.........................              -             -              -            -           -
    Fair value of new hedge positions..........              -             -              -            -           -
     Ending accumulated derivative gain........              -             -              -            -           -
  Translation adjustments......................              -             -              -            -           -
  Total comprehensive income, net of tax.......

Stock options exercised........................              -             -             24            -       4,599
Tax benefit related to stock options...........              -             -              -            -           -
Loans forgiven.................................              -             -              -            -           -
Dividends declared on common stock.............              -             -              -            -           -
Dividends declared on $2.28 cumulative
  preferred stock..............................              -             -              -            -           -
Dividends declared on $2.625 cumulative
  convertible preferred stock..................              -             -              -            -           -
Repurchase of $2.28 cumulative
  preferred stock..............................              -             -              -         (129)          -
                                                   -----------    ----------     ----------   ----------  ----------
Balance at June 30, 2001.......................    $       140    $      276     $    3,289   $   (1,907) $  404,756
                                                   ===========    ==========     ==========   ==========  ==========


<CAPTION>
                                                                Accumulated
                                                                   Other         Notes         Total
                                                     Retained  Comprehensive  Receivable      Stock-
                                                    (Deficit)     Income       from Key      holders'
                                                     Earnings   Net of Tax     Employees      Equity
                                                    ---------   ----------    ----------   ------------
<S>                                                 <C>         <C>           <C>          <C>
Balance at December 31, 2000...................        (11,820)     2,178          (884)     391,534
Comprehensive income:
  Net income, six months ended
    June 30, 2001..............................         70,043          -             -       70,043
    Cumulative effect of change in accounting
     principle - January 1, 2001...............              -    (22,527)            -      (22,527)
    Reclassification adjustment for settled
     contracts.................................              -     17,084             -       17,084
    Changes in fair value of outstanding
     hedging positions.........................              -     14,494             -       14,494
    Fair value of new hedge positions..........              -     13,739             -       13,739
                                                                 --------      --------   ----------
     Ending accumulated derivative gain........              -     22,790             -       22,790
  Translation adjustments......................              -       (291)            -         (291)
                                                                                          ----------
  Total comprehensive income, net of tax.......                                               92,542
                                                                                          ----------

Stock options exercised........................              -          -             -        4,623
Tax benefit related to stock options...........              -          -             -            -
Loans forgiven.................................              -          -             -            -
Dividends declared on common stock.............         (3,257)         -             -       (3,257)
Dividends declared on $2.28 cumulative
  preferred stock..............................         (1,546)         -             -       (1,546)
Dividends declared on $2.625 cumulative
  convertible preferred stock..................         (3,622)         -             -       (3,622)
Repurchase of $2.28 cumulative
  preferred stock..............................              -          -             -         (129)
                                                    ----------   --------      --------   ----------
Balance at June 30, 2001.......................     $   49,798   $ 24,677      $   (884)  $  480,145
                                                    ==========   ========      ========   ==========
</TABLE>



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

                                       6
<PAGE>

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

GENERAL

      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, 2000.
The interim consolidated financial statements as of June 30, 2001 and for the
three and six month periods ended June 30, 2001 and 2000 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, 2001 are not necessarily indicative of the results of operations
expected for the year ended December 31, 2001.

      Prior year's amounts in the interim consolidated financial statements and
notes have been reclassified as appropriate to conform to the presentation used
in 2001.

EARNINGS PER SHARE OF COMMON STOCK

      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 $2.6 million and $5.2
million, respectively, for each of the three and six month periods ended June
30, 2001 and 2000. 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 4,494,345 and 573,943 for the three-month periods ended June 30,
2001 and 2000, respectively, and by 4,473,008 and 446,815 for the six months
ended June 30, 2001 and 2000, respectively. The numerators and the denominators
for these periods were adjusted to reflect these potential shares in calculating
fully diluted earnings per share.

OTHER INFORMATION

    Bethel Treating Facility. In December 2000, we signed an agreement with
Anadarko Petroleum Corporation for the sale of all the outstanding stock of our
wholly-owned subsidiary, Pinnacle 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 $11.2 million in the first quarter of 2001.

    Western Gas Resources-California, Inc. In January 2000, we sold all the
outstanding stock of our wholly-owned subsidiary, Western Gas
Resources-California, Inc. ("WGR-California") for $14.9 million. The only asset
of this subsidiary was a 162 mile pipeline in the Sacramento basin of
California. The pipeline was acquired through the exercise of an option by us in
a transaction which closed simultaneously with the sale of WGR-California. We
recognized a pre-tax gain on the sale of approximately $5.3 million in the first
quarter of 2000.

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

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

    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.

                                       7
<PAGE>

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

     Of the $22.5 million decrease to Accumulated other comprehensive income
resulting from the January 1, 2001 adoption of SFAS 133, $17.1 million was
reversed in the first six months of 2001 with gains and losses from the
underlying transactions recognized through Total revenues. An additional $4.9
million of this transition entry is currently anticipated to be recognized
through Total revenues in the remaining two quarters of 2001. The non-cash
impact to our results of operations in the first six months of 2001 resulting
from the adoption of mark-to-market accounting for our marketing activities
resulted in additional pre-tax income of $2.2 million.

     The net loss recognized in earnings through Sale of residue gas and Sale of
natural gas liquids during the first six months of 2001 from hedging activities
was $6.5 million. This includes $184,000 as a result of hedge ineffectiveness
due to the use of crude oil swaps in hedging the variability in the sales price
of normal butane. All of the company's hedges are expected to continue to be
highly effective 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, 2001, approximately $10.6 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 2002.

ADOPTION OF STOCKHOLDER RIGHTS PLAN

     In the first quarter of 2001, we adopted a Stockholder Rights Plan under
which rights were distributed as a dividend at the rate of one right for each
share of our common stock held by stockholders of record as of the close of
business on April 9, 2001. The Rights Plan was not adopted in response to any
efforts to acquire control of our company. The Rights Plan, however, is designed
to deter coercive takeover tactics including the accumulation of shares in the
open market or through private transactions and to prevent an acquirer from
gaining control of our company without offering a fair and adequate price to all
of our stockholders.

     Each right initially will entitle stockholders to buy one unit consisting
of 1/100/th/ of a share of a new series of preferred stock for $180 per unit.
The right generally will be exercisable only if a person or group acquires
beneficial ownership of 15 percent or more of our then outstanding common stock
or commences a tender or exchange offer upon consummation of which a person or
group would beneficially own 15 percent or more of our then outstanding common
stock. The rights will expire on March 22, 2011.

SUPPLEMENTARY CASH FLOW INFORMATION

        Interest paid was $15.1 million and $17.7 million for the six months
ended June 30, 2001 and 2000, respectively.

        Estimated tax payments of $9.4 million were made during the six months
ended June 30, 2001. No income taxes were paid during the six months ended June
30, 2000.

SEGMENT REPORTING

     We operate in four principal business segments, as follows: Gas Gathering
and Processing, Production, Marketing and Transmission. These segments are
separately monitored by management for performance against our internal forecast
and 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 our Gas Gathering and Processing segment, we connect producers' wells 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. Our Marketing segment sells the residue gas and NGLs
extracted at our processing facilities.

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

                                       8
<PAGE>

    Our Marketing segment buys and sells gas and NGLs nationwide and in Canada
from or to a variety of customers. In addition, this segment also markets gas
and NGLs produced by our gathering, processing and production assets. Our
Canadian marketing operations, which are immaterial for separate presentation,
are included in this segment. The Marketing segment also includes losses
associated with our equity gas and NGL hedging program of $(1.7) million and
$(6.5) million for the three months ended June 30, 2001 and June 30, 2000,
respectively, and $(16.0) million and $(9.6) million for the six months ended
June 30, 2001 and 2000, respectively.

    The Transmission 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.

    The following table sets forth our segment information as of and for the
three and six months ended June 30, 2001 and 2000 (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.

<TABLE>
<CAPTION>
                                             Gas
                                          Gathering                                                         Elim-
                                             and                                   Trans-                  inating
                                         Processing   Production    Marketing     mission    Corporate     Entries        Total
                                         ----------   ----------   -----------   ---------   ---------   -----------   ----------
<S>                                      <C>          <C>          <C>           <C>         <C>         <C>           <C>
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
Other, net.............................           -           -         (4,409)          -       1,076            -        (3,333)
Intersegment sales.....................     219,730      29,417          9,125       4,391          13     (262,676)            -
                                         ----------   ---------    -----------   ---------   ---------   ----------    ----------
Total revenues.........................     235,896      29,525        876,113       6,700       4,483     (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    $    16,518   $   4,528   $   4,810   $   (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
                                         ==========   =========    ===========   =========   =========   ==========    ==========
</TABLE>

<TABLE>
<CAPTION>
                                             Gas
                                          Gathering                                                          Elim-
                                             and                                   Trans-                  inating
                                         Processing   Production    Marketing     mission    Corporate     Entries       Total
                                         ----------   ----------   -----------   ---------   ---------   -----------   ----------
<S>                                      <C>          <C>          <C>           <C>         <C>         <C>           <C>
Quarter ended June 30, 2000
Revenues from unaffiliated customers...  $    6,768   $    1,144   $   637,162   $   1,877   $      35   $        8    $  646,994

Interest income........................           1            -             3           -       6,419       (6,353)           70
Other, net.............................       1,692           41        (6,477)          -        (504)           -        (5,248)
Intersegment sales.....................     186,001       17,603        12,948       4,315          13     (220,880)            -
                                         ----------   ----------   -----------   ---------   ---------   ----------    ----------
Total revenues.........................     194,462       18,788       643,636       6,192       5,963     (227,225)      641,816
                                         ----------   ----------   -----------   ---------   ---------   ----------    ----------
Product purchases......................     143,245        1,028       647,271           -         (65)    (214,752)      576,727
Plant operating expense................      15,416          291             -       1,996        (328)        (275)       17,100
Oil and gas exploration
    and production expense.............          31        8,456             -           -           -       (6,696)        1,791
                                         ----------   ----------   -----------   ---------   ---------   ----------    ----------
Operating profit.......................  $   35,770   $    9,013   $    (3,635)  $   4,196   $   6,356   $   (5,502)   $   46,198
                                         ==========   ==========   ===========   =========   =========   ==========    ==========
</TABLE>


                                       9
<PAGE>

<TABLE>
<S>                                      <C>          <C>          <C>           <C>         <C>         <C>           <C>
Depreciation, depletion and
 amortization..........................       8,991        3,493            40         409       1,290            -        14,223
Interest expense......................                                                                                      7,809
Gain on sale of assets................                                                                                       (335)
Selling and administrative expense ...                                                                                      8,100
                                                                                                                       ----------
Income (loss) before income taxes.....                                                                                 $   16,401
                                                                                                                       ==========

Identifiable assets....................  $  552,073   $  109,068   $        68   $  46,856   $  38,907   $        -    $  746,972
                                         ==========   ==========   ===========   =========   =========   ==========    ==========
</TABLE>

<TABLE>
<CAPTION>
                                             Gas
                                          Gathering                                                         Elim-
                                             and                                   Trans-                  inating
                                         Processing   Production    Marketing     mission    Corporate     Entries       Total
                                         ----------   ----------   -----------   ---------   ---------   -----------   ----------
<S>                                      <C>          <C>          <C>           <C>         <C>         <C>           <C>
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
Other, net.............................           4           (1)      (13,768)           2      2,453             -       (11,310)
Intersegment sales.....................     537,803       81,567        20,611        8,658         27      (648,666)            -
                                         ----------   ----------   -----------   ----------  ---------   -----------   -----------
Total revenues.........................     568,008       82,395     2,065,496       13,644     11,242      (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   $    17,697   $    9,812  $  11,181   $    (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
                                         ==========   =========    ===========   ==========  =========   ===========   ===========
</TABLE>

<TABLE>
<CAPTION>
                                             Gas
                                          Gathering                                                         Elim-
                                             and                                   Trans-                  inating
                                         Processing   Production    Marketing     mission    Corporate     Entries       Total
                                         ----------   ----------   -----------   ---------   ---------   -----------   ----------
<S>                                      <C>          <C>          <C>           <C>         <C>         <C>           <C>
Six months ended June 30, 2000
Revenues from unaffiliated customers...  $   18,174   $    2,130   $ 1,189,494   $   4,255   $      61   $         -   $ 1,214,114
Interest income........................          34            2            27           -      12,257       (12,021)          299
Other, net.............................       1,672           41        (9,690)          -         532             -        (7,445)
Intersegment sales.....................     320,343       27,907        39,281       8,719          17      (396,267)            -
                                         ----------   ----------   -----------   ---------   ---------   -----------   -----------
Total revenues.........................     340,223       30,080     1,219,112      12,974      12,867      (408,288)    1,206,968
                                         ----------   ----------   -----------   ---------   ---------   -----------   -----------
Product purchases......................     246,253        1,532     1,219,958           -         (90)     (389,783)    1,077,870
Plant operating expense................      28,478          308             -       4,264         (72)         (616)       32,362
Oil and gas exploration
   and production expense..............          31       12,602             -           -           -        (6,696)        5,937
                                         ----------   ----------   -----------   ---------   ---------   -----------   -----------
Operating profit.......................  $   65,461   $   15,638   $      (846)  $   8,710   $  13,029   $   (11,193)  $    90,799
                                         ==========   ==========   ===========   =========   =========   ===========   ===========

Depreciation, depletion and
 amortization..........................      17,562        6,382            80         833       2,675             -        27,532
</TABLE>

                                       10
<PAGE>

<TABLE>
<S>                                      <C>          <C>          <C>           <C>         <C>         <C>           <C>
Interest expense.....................                                                                                       16,027
Gain on sale of assets...............                                                                                       (5,634)
Selling and administrative expense...                                                                                       15,489
                                                                                                                       -----------
Income (loss) before income taxes....                                                                                  $    37,385
                                                                                                                       ===========

Identifiable assets..................    $  552,073   $  109,068   $        68   $  46,856   $  38,907   $         -   $   746,972
                                         ==========   ==========   ===========   =========   =========   ===========   ===========
</TABLE>

LEGAL PROCEEDINGS

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

                                       11
<PAGE>

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, 2001 and 2000. Prior year amounts have been
reclassified as appropriate to conform to the presentation used in 2001. 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 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.

Results of Operations

Three and six months ended June 30, 2001 compared to the three and six months
ended June 30, 2000 (Dollars in thousands, except per share amounts and
operating data).

<TABLE>
<CAPTION>
                                                    Three Months Ended                      Six Months Ended
                                                          June 30,                              June 30,
                                                  -----------------------     Percent  ---------------------------   Percent
                                                     2001          2000       Change        2001          2000       Change
                                                  ----------   ----------     ------   ------------   ------------   ------
<S>                                               <C>          <C>            <C>      <C>            <C>            <C>
Financial results:
Revenues........................................  $  887,024   $  641,816        38    $  2,084,300   $  1,206,968      73
Gross profit....................................      59,853       32,310        85         140,632         68,901     104
Net income......................................      29,453       10,580       178          70,043         23,586     197
Income per share of common stock................         .82          .25       228            2.00            .57     251
Income per share of common stock -
     fully diluted..............................         .77          .24       221            1.85            .56     230
Net cash provided by
  operating activities..........................  $   31,754   $    5,925       436    $    138,298   $     15,745     778

Operating data:
Average gas sales (MMcf/D)......................       1,835        1,670        10           1,755          1,735       1
Average NGL sales (MGal/D)......................       2,370        2,815       (16)          2,300          2,970     (23)
Average gas prices ($/Mcf)......................  $     4.53   $     3.34        36    $       5.68   $       2.91      95
Average NGL prices ($/Gal)......................  $      .53   $      .48        10    $        .58   $        .48      21
</TABLE>


     Net income increased $18.9 million and $46.5 million for the three and six
months ended June 30, 2001 compared to 2000. The increase in net income for
these periods is primarily attributable to significantly higher gas and NGL
prices in 2001 compared to the prior year, increased production from the Powder
River basin coal bed methane development, and improved results from our
marketing segment.

     Revenues from the sale of gas increased $249.7 million to $756.5 million
for the three months ended June 30, 2001 compared to the same period in 2000.
This increase was primarily due to an improvement in product prices in 2001 and
to a lesser extent an increase in sales of natural gas purchased from third
parties. Average gas prices realized by us increased $1.19 per Mcf to $4.53 per
Mcf for the quarter ended June 30, 2001 compared to the same period in 2000.
Included in the realized gas price were approximately $795,000 of losses
recognized in the three months ended June 30, 2001 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 2001 and in 2002. See further
discussion in " - Liquidity and Capital Resources - Risk Management Activities."
Average gas sales volumes increased 165 MMcf per day to 1,835 MMcf per day for
the quarter ended June 30, 2001 compared to the same period in 2000.

     Revenues from the sale of gas increased $881.7 million to $1,801.4 million
in the six months ended June 30, 2001 compared to the same period in 2000. This
increase was primarily due to an improvement in product prices. Average gas
prices realized by us increased $2.77 per Mcf to $5.68 per Mcf in the six months
ended June 30, 2001 compared to the same period in 2000. Included in the
realized gas price were approximately $14.3 million of losses recognized in the
six months

                                       12

<PAGE>

ended June 30, 2001 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 2001 and in 2002. See further discussion in " - Liquidity and
Capital Resources - Risk Management Activities." Average gas sales volumes
increased 16 MMcf per day to 1,751 MMcf per day in the six months ended June 30,
2001 compared to the same period in 2000.

     Revenues from the sale of NGLs decreased $7.7 million in the second quarter
of 2001 compared to the same period in 2000. This decrease is due to a reduction
in sales volume which more than offset an increase in product prices. Average
NGL prices realized by us increased $.05 per gallon to $.53 per gallon in the
second quarter of 2001 compared to the same period in 2000. Included in the
realized NGL price were approximately $730,000 of losses recognized in the
second quarter of 2001 related to futures positions on equity NGL volumes. We
have entered into additional futures positions for a portion of our equity NGL
production for the remainder of 2001. See further discussion in " - Liquidity
and Capital Resources - Risk Management Activities." Average NGL sales volumes
decreased 445 MGal per day to 2,370 MGal per day in the second quarter of 2001
compared to the same period in 2000. 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.

     Revenues from the sale of NGLs decreased approximately $13.6 million in the
six months ended June 30, 2001 compared to the same period in 2000. This
decrease is due to a reduction in sales volume which more than offset an
increase in product prices. Average NGL prices realized by us increased $.10 per
gallon to $.58 per gallon in the six months ended June 30, 2001 compared to the
same period in 2000. Included in the realized NGL price were approximately $1.7
million of losses recognized in the six months ended June 30, 2001 related to
futures positions on equity NGL volumes. We have entered into additional futures
positions for a portion of our equity NGL production for the remainder of 2001.
See further discussion in " - Liquidity and Capital Resources - Risk Management
Activities." Average NGL sales volumes decreased 670 MGal per day to 2,300 MGal
per day in the six months ended June 30, 2001 compared to the same period in
2000. 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.
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.

     Product purchases increased by $207.8 million and $793.3 million for the
quarter and six months ended June 30, 2001 compared to the same period in 2000
primarily as a result of the increase in commodity prices. Overall, combined
product purchases as a percentage of sales of all products decreased to 90% and
91% for the quarter and six months ended June 30, 2001 from 92% for the same
periods in 2000, respectively. The decrease in the product purchase percentage
resulted from improved marketing margins.

     Marketing margins on residue gas averaged $0.10 per Mcf in both the second
quarter and the six months ended June 30, 2001. This represents a significant
increase as compared to the margin realized during the second quarter of 2000 of
$.01 per Mcf and during the six months ended June 30, 2000 of $.02 per Mcf,
respectively. The increase in margin for the quarter and six months ended June
30, 2001 primarily resulted from the mark-to-market of transactions utilizing
our firm transportation capacity during July through December 2001, and the
mark-to-market of storage transactions entered into in the first six months of
2001. The increase in margin for the quarter and six months ended June 30, 2001
primarily resulted from the mark-to-market of contracts for firm transportation
capacity during July through December 2001 from Wyoming to the Mid-continent
where regional differentials widened and the mark-to-market of storage
transactions entered into in the first six months of 2001. Under mark-to-market
accounting, which was adopted on January 1, 2001, the margin 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 $0.007
per gallon in both the second quarter and the six months ended June 30, 2001.
This margin remained relatively constant to the same periods in 2000. 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 addition, during the first quarter
of 2001, we reserved a total of $1.0 million for doubtful accounts. This reserve
is not included in the calculation of the marketing margins and is reported in
Selling and administrative expenses.

     Plant operating expense increased $1.1 million in the second quarter of
2001 and by $2.9 million in the six months ended June 30, 2001 compared to the
same periods in 2000. This increase is primarily due to additional leased
compression in the Powder River basin coal bed development and higher fuel costs
at our plant facilities.

     Oil and gas exploration and production expenses increased by $7.3 million
and $12.8 million in the second quarter and the six months ended June 30, 2001
as compared to the same periods in 2000 primarily as a result of our increasing
operations in the Powder River basin coal bed methane development.

                                       13

<PAGE>

     Depreciation, depletion and amortization increased by $1.1 million and $2.2
million in the second quarter and the six months ended June 30, 2001 as compared
to the same periods in 2000 primarily as a result of our increasing operations
in the Powder River basin coal bed methane development.


Other Information

     Bethel Treating Facility. In December 2000, we signed an agreement with
Anadarko Petroleum Corporation for the sale of all the outstanding stock of our
wholly-owned subsidiary, Pinnacle 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 $11.2 million in the first quarter of 2001.

     Western Gas Resources-California, Inc. In January 2000, we sold all the
outstanding stock of our wholly-owned subsidiary, Western Gas Resources-
California, Inc. ("WGR-California") for $14.9 million. The only asset of this
subsidiary was a 162 mile pipeline in the Sacramento basin of California. The
pipeline was acquired through the exercise of an option by us in a transaction
which closed simultaneously with the sale of WGR-California. We recognized a
pre-tax gain on the sale of approximately $5.3 million in the first quarter of
2000.

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

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

     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.


Business Strategy

     Improved product prices throughout 2000 and continuing into 2001 have
strengthened our financial position allowing us to emphasize the growth aspects
of our business strategy. Our long-term business plan is to increase our
profitability by: (i) optimizing the efficiency and utilization of our existing
operations; (ii) developing natural gas reserves and increasing production
volumes on our existing acreage positions; and (iii) investing in projects or
acquiring assets that complement and extend our core natural gas gathering,
processing, production and marketing businesses.

     We are actively evaluating acquisitions of either assets or companies.
These acquisitions can be related to gathering and processing or production with
emphasis on properties located in the Rocky Mountains or Canada. Capital
expenditures budgeted for existing operations in 2001 are estimated to be
approximately $172.7 million. This includes approximately $100.2 million related
to gathering, processing and pipeline assets and approximately $46.8 million for
the acquisition of undeveloped acreage and development of gas reserves in the
Powder River basin. This budget will be increased to provide for acquisitions if
approved by our board of directors. In the first six months of 2001, our capital
expenditures totaled $75.2 million.

     We consistently seek to improve the profitability of our existing
operations by increasing natural gas throughput levels through new well
connections and expansion of our gathering systems, increasing our efficiency
through the modernization of equipment and consolidation of existing gathering
and processing facilities, evaluating the economic performance of each of our
operating facilities to ensure that a targeted rate of return is achieved and
controlling operating and overhead expenses.

     We continually seek to increase reserves dedicated to our gathering and
processing facilities. Our operations are located in some of the most actively
drilled oil and gas producing basins in the United States. We enter into
agreements under which we gather and process natural gas produced on acreage
dedicated to us by third parties. We contract for production from new wells or
undeveloped acreage in order to replace declines in existing reserves or
increase reserves that are dedicated for gathering and processing at our
facilities. At December 31, 2000, our estimated dedicated reserves totaled 2.7
Tcf. In 2000,

                                       14
<PAGE>

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 222% of throughput. In order to obtain additional dedicated
acreage and to secure contracts on favorable terms, we may participate to a
limited extent with third-party producers in exploration and production
activities to supply our facilities. For the same reason, we may also offer to
sell ownership interests in our facilities to selected producers.

    We selectively participate in exploration and production activities largely
to secure additional gas supply for our facilities. Beginning in 1997, we
substantially increased our investment in the acquisition of undeveloped acreage
and development of the Powder River basin coal bed methane. We have acquired
drilling rights on approximately 520,000 net acres in the basin. At December 31,
2000 we had proved developed and undeveloped reserves of approximately 350 Bcf
on a portion of this acreage. We also have participated in the development of
properties in southwest Wyoming and Colorado. As of December 31, 2000, these
properties had an additional 58 Bcf of proved developed and undeveloped
reserves. This represents an increase of approximately 50% in our proved
reserves from December 31, 1999. We currently estimate a net total of 2.2 Tcf of
probable or possible reserves on an unrisked basis associated with undeveloped
acreage in these areas. There can be no assurance, however, as to the ultimate
recovery of these probable or possible reserves. We will also consider investing
in other exploration and production prospects that we consider to be low risk
and complementary to our other business segments.

    We will continue to invest in projects that complement and extend our core
natural gas gathering, processing, production and marketing businesses including
the consideration of expansion into additional geographic areas in the
continental United States and Canada.

    In the third quarter of 2000, our board of directors began a search to
identify and evaluate both internal and external candidates to replace our
current Chief Executive Officer and President, Lanny Outlaw who had informed the
board of his intention to retire May 31, 2001 in accordance with his contract.
In May 2001, Mr. Outlaw agreed to postpone his retirement until November 30,
2001 in order to allow the board of directors additional time to secure the
ideal candidate as his successor. Mr. Outlaw intends to serve his remaining term
on the board of directors which expires in May 2003.

Liquidity and Capital Resources

    Our sources of liquidity and capital resources historically have been net
cash provided by operating activities, funds available under our financing
facilities and proceeds from offerings of debt and equity securities. In the
past, these sources have been sufficient to meet our needs and finance the
growth of our business. We can give no assurance that the historical sources of
liquidity and capital resources will be available for future development and
acquisition projects, and we may be required to seek alternative financing
sources. Product prices, sales of inventory, the volumes of natural gas
processed by our facilities, the volume of natural gas produced from our
producing properties, the margin on third-party product purchased for resale, as
well as the timely collection of our receivables will all affect future net cash
provided by operating activities. Additionally, our future growth will be
dependent upon obtaining additions to dedicated plant reserves, acquisitions,
new project development, marketing, 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. Depending on the timing and the amount of our
future projects, we may be required to seek additional sources of capital. Our
ability to secure such capital is restricted by our financing facilities,
although we may request additional borrowing capacity from our lenders, seek
waivers from our lenders to permit us to borrow funds from third parties, seek
replacement financing facilities from other lenders, use stock as a currency for
acquisitions, sell existing assets or a combination of alternatives. While we
believe that we would be able to secure additional financing, if required, we
can provide no assurance that we will be able to do so or as to the terms of any
additional financing. We also believe that cash provided by operating activities
and amounts available under the Revolving Credit Facility will be sufficient to
meet our debt service and preferred stock dividend requirements for 2001.

    During the past several years 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 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.

                                       15
<PAGE>

    We have effective shelf registration statements filed with the 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, 2001 are
summarized as follows (dollars in thousands):

<TABLE>
<S>                                                                                     <C>
Sources of funds:
         Borrowings under the Revolving Credit Facility.............................    $     291,200
         Proceeds from the dispositions of property and equipment...................           38,075
         Net cash provided by operating activities..................................          138,298
         Proceeds from exercise of common stock options.............................            4,623
                                                                                        -------------
              Total sources of funds................................................    $     472,196
                                                                                        =============

Uses of funds:
         Payments related to long-term debt (including debt issue costs)............    $     344,900
         Capital expenditures.......................................................           74,539
         Dividends paid.............................................................            8,413
         Other......................................................................              857
                                                                                        -------------
              Total uses of funds...................................................    $     428,709
                                                                                        =============
</TABLE>

     Additional sources of liquidity available to us are our inventories of gas
and NGLs in storage facilities. We store gas and NGLs primarily to ensure an
adequate supply for long-term sales contracts and for resale during periods when
prices are favorable. We held gas in storage and in imbalances of approximately
11.5 Bcf at an average purchase cost of $5.61 per Mcf at June 30, 2001 compared
to 9.5 Bcf at an average purchase cost of $3.06 per Mcf at June 30, 2000 under
storage contracts at various third-party facilities. These positions will be
substantially liquidated within the next twelve months at prices prevailing at
that time as adjusted by any associated derivative instruments. Under mark-to-
market accounting, the profit to be earned on these transactions was recorded in
the month of origin.

     We held NGLs in storage of 6,930 MGal, consisting primarily of propane and
normal butane, at an average cost of $0.45 per gallon and 8,670 MGal at an
average cost of $0.34 per gallon at June 30, 2001 and 2000, respectively, at
various third-party storage facilities. At June 30, 2001, we had no significant
hedging contracts in place for anticipated sales of stored NGLs.

Preferred Stock Repurchase Program

     Through the first six months of 2001, we purchased in open market
transactions a total of 5,100 shares of our $2.28 cumulative preferred stock for
a total cost, including broker commissions, of approximately $129,000, or an
average of $25.25 per share of preferred stock. These shares will be retired.
Our board of directors has authorized the re-purchase from time to time of up to
an additional $1.0 million of preferred stock in open market transactions.

Capital Investment Program

     Primarily as a result of additional drilling behind our systems and in the
Powder River Basin, we have increased our capital budget for the year ending
December 31, 2001 by approximately $36.3 million. We now expect capital
expenditures related to existing operations to be approximately $172.7 million
during 2001, consisting of the following: (i) approximately $100.2 million
related to gathering, processing and pipeline assets, of which $8.5 million is
for maintaining existing facilities; (ii) approximately $64.8 million related to
exploration and production activities; and (iii) approximately $7.7 million for
miscellaneous items. Overall, capital expenditures in the Powder River basin
coal bed methane development and in southwest Wyoming operations represent 40%
and 20%, respectively, of the total 2001 budget.

     As of June 30, 2001, we have expended $75.2 million, consisting of the
following: (i) $37.2 million related to gathering, processing and pipeline
assets, of which $2.6 million is for maintaining existing facilities; (ii) $35.4
million related to exploration and production activities; and (iii) $2.6 million
for miscellaneous items.

Coal Bed Methane - We continue to develop our Powder River basin coal bed gas
reserves and the associated gathering system in 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. In the first six months of
2001, we continued to be the largest producer of

                                       16
<PAGE>

natural gas (together with our partner), the largest gatherer of natural gas and
the largest gas transporter out of the basin. At June 30, 2001, we held the
drilling rights on approximately 780,000 gross acres, or 520,000 net acres, in
the basin. As of December 31, 2000, we had established proven developed and
undeveloped reserves totaling 350 Bcf on a portion of this acreage. This
represented a 50% increase in proved reserves as compared to December 31, 1999.
As of June 30, 2001, we estimated that there was a net total of 2.1 Tcf of
probable and possible reserves on an unrisked basis associated with undeveloped
acreage in this area. There can be no assurance, however, as to the ultimate
recovery of these reserves.

    We participated in the drilling of 310 wells in the first half of 2001 and
plan to participate in a total of 840 wells in 2001. The average drilling,
completion and gathering cost for our coal bed methane gas wells is
approximately $70,000 to $90,000 per well with proved reserves per well of
approximately 330 MMcf. Our average finding and development costs in this area
are estimated to be $.30 per Mcf. As deeper wells are drilled to the Big George
coal, reserves per well are expected to increase as will the average cost per
well. It is expected that the deeper Big George wells will result in a higher
rate of return. Total production from wells in which we own an interest has
increased from an average of approximately 128 MMcf per day at December 31, 1999
to 219 MMcf per day at June 30, 2001. We currently anticipate production rates
of 270 MMcf per day from this area by the end of 2001 and 300 MMcf per day from
this area by March 31, 2002. This represents a three month delay in achieving
our production goals due to several factors. These factors include weather
delays during the spring drilling season, delays in receiving water discharge
permits and less than forecasted production from the Hoe Creek area. Within the
Hoe Creek area, approximately 150 gross wells have not responded to de-watering
as expected and may not achieve our original estimate of production or reserves.
All of the remaining areas under development in the Wyodak coal continue to
produce at or above forecasted levels.

    We are currently evaluating eight pilot development areas in the Big George.
Several of these pilots are in close proximity to leases operated by third-
parties which are currently producing growing volumes of natural gas. By the end
of 2001, we expect to have drilled 250 gross wells in the pilot areas. Five of
these pilot areas are currently in the de-watering phase. Our All Night Creek
pilot is currently producing 450 Mcf per day of gas from 18 wells. An additional
10 wells in this area are capable of producing gas, but are shut in as a result
of regulations restricting the venting of natural gas. Compression is expected
to be operational by late August and all 28 wells should then begin delivering
gas to market.

    Future drilling on federal acreage will be delayed subject to completion of
the Powder River Basin Oil & Gas Environmental Impact Statement. We anticipate
the study to be completed in the third quarter of 2002. Our drilling plans for
2001 are not expected to be substantially impacted by this study due to our
large inventory of non-federal drilling locations and the issuance of drilling
permits by the Bureau of Land Management, BLM, for approximately 250 well
locations to prevent drainage of federal acreage.

    Additionally, the Wyoming Department of Environmental Quality, DEQ, has
revised some standards for surface water discharge that have allowed the
issuance of most of the permits that apply to the Cheyenne and Belle Fourche
drainage areas. We continue to work with both the Wyoming DEQ and Montana DEQ to
finalize an agreement between the agencies allowing for water discharge in the
Powder River drainage area in which most of our Big George prospects are
located. We anticipate that the Wyoming DEQ will begin issuing permits for the
Powder River drainage area in the third quarter of 2001. The majority of wells
on our acreage producing from the Wyodak formation drain into the Cheyenne and
Belle Fourche drainage areas. We can make no assurance that the conditions under
which additional permits will be granted will not impact the level of drilling
or the timing of production.

    In addition to the revenues earned from the production of our coal bed
methane gas, we also earn fees for gathering and transporting the natural gas.
At June 30, 2001, we were gathering 283 MMcf per day of our own production and
of other third-party producers. Of that volume, approximately 136 MMcf per day
was transported through our MIGC pipeline.

    Our capital budget in this area provides for expenditures of approximately
$67.2 million during 2001. This capital budget includes approximately $46.8
million for drilling costs for our interest in approximately 840 wells,
production equipment and undeveloped acreage and $20.4 million for compression.
Depending upon future drilling success, we may need to make additional capital
expenditures to continue expansion in this basin. Due to drilling and regulatory
uncertainties which are beyond our control, we can make no assurance that we
will incur this level of capital expenditure. In the first six months of 2001,
capital expenditures in this area totaled $39.5 million.

    In 1998, we joined with other industry participants to form Fort Union Gas
Gathering, L.L.C., to construct a 106-mile long, 24-inch gathering pipeline and
treater to gather and treat natural gas in the Powder River basin in northeast
Wyoming. We own a 13% equity interest in Fort Union and are the construction
manager and field operator. The gathering header has a capacity of approximately
435 MMcf per day and in June 2001 it had throughput of approximately 310 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. In 1999, we entered
into a ten year agreement

                                       17
<PAGE>

for firm gathering services on 60 MMcf per day of capacity at $.14 per Mcf on
Fort Union. In the fourth quarter of 2000, we and the other participants in the
Fort Union Gas Gathering, L.L.C. approved an expansion of the system.
Construction of the 62 mile expansion has begun and will increase the system
capacity by an additional 200 MMcf per day. This project is expected to be
completed in the third quarter of 2001. This expansion, which is anticipated to
cost $25.7 million, will be project financed and will require a cash investment
by us of approximately $500,000. Also in connection with the expansion, we will
increase our commitment for firm gathering services by an additional 23 MMcf per
day of capacity at $.14 per Mcf .

    Southwest Wyoming. Our facilities in southwest Wyoming are comprised of the
Granger and Lincoln Road facilities, or collectively the Granger Complex, and
our Red Desert facility. These facilities have a combined operational capacity
of 327 MMcf per day and processed an average of 183 MMcf per day in the first
six months of 2001. Our capital budget in this area provides for expenditures of
approximately $35.2 million during 2001. This capital budget includes
approximately $14.4 million for drilling costs and production equipment and
approximately $20.8 million related to the gathering systems and plant
facilities. Due to drilling and regulatory uncertainties which are beyond our
control, we can make no assurance that we will incur this level of capital
expenditure. During the first six months of 2001, we expended $13.9 million in
this area which includes the purchase of the remaining 50% interest in a
gathering system serving the Granger Complex.

    Under a 1997 agreement with an active producer in this area, we participate
in approximately 248,000 gross acres, or approximately 35,000 net acres. In
2001, we expect to participate in 8 gross development wells, or 2 net
development wells, in the Jonah field of southwest Wyoming. We also expect to
participate in the drilling of up to 38 gross wells, or 2 net wells in the
Pinedale Anticline area of the Hoback basin during 2001. The expected drilling
and completion costs per gross well are approximately $2.4 million to $3.5
million and the average well depth in this area approximates 13,000 feet. Our
average finding and development costs are estimated to be $.57 per Mcf. We have
established proven developed and undeveloped reserves totaling 52 Bcf at
December 31, 2000. This represents a 73% increase as compared to December 31,
1999. As of June 30, 2001, we estimate a net total of 102 Bcf of probable and
possible reserves on an unrisked basis associated with undeveloped acreage in
this area. There can be no assurance, however, as to the ultimate recovery of
these reserves.

Financing Facilities

    Revolving Credit Facility. The Revolving Credit Facility is with a syndicate
of banks and provides for a maximum borrowing commitment of $250 million
consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A,
and a $167 million Revolving Credit Facility, or Tranche B, which matures on
April 30, 2004. At June 30, 2001, no amounts were 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, 2001, the interest rate payable on any
borrowings under this facility would have been approximately 5.0%. We are
required to maintain a total debt to capitalization ratio of not more than 55%,
and a senior debt to capitalization ratio of not more than 40% through December
31, 2001 and of not more than 35% thereafter. The agreement also requires a
quarterly test of the ratio of EBITDA (excluding some non-recurring items) for
the last four quarters, to interest and dividends on preferred stock for the
same period. The ratio must exceed 1.80 to 1.0 through September 30, 2001 and
increases periodically to 3.25 to 1.0 by December 31, 2002. This facility is
guaranteed and secured via a pledge of the stock of some of our 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, 2001 are as indicated in the
following table (dollars in thousands):

<TABLE>
<CAPTION>
                                Interest         Final
     Issue Date        Amount     Rate          Maturity                      Principal Payments Due
------------------    --------  --------    ----------------    ------------------------------------------------
<S>                   <C>       <C>         <C>                  <C>
October 27, 1992      $ 25,000   7.99%      October 27, 2003     $8,333 on each of October 27, 2001 through 2003
December 27, 1993       25,000   7.23%      December 27, 2003    single payment at maturity
October 27, 1994        25,000   9.05%      October 27, 2001     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
                      --------
                      $150,000
                      ========
</TABLE>


    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

                                       18
<PAGE>

more than 60% through December 31, 2001 and of not more than 55% thereafter and
a senior debt to capitalization ratio of not more than 40% through March 2002
and not more than 35% thereafter. This agreement also requires an EBITDA to
interest ratio of not less than 3.00 to 1.0 increasing to a ratio of not less
than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt
ratio of not less than 4.75 to 1.0 increasing to a ratio of not less than 5.50
to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non-
recurring items. In addition, this agreement contains a calculation limiting
dividends under which approximately $87.0 million was available at June 30,
2001. We are currently paying an annual fee of 0.50% on the amounts outstanding
on the Master Shelf Agreement. This fee will continue until we receive an
implied investment grade rating on our senior secured debt from Moody's
Investors Service or Standard & Poor's. Borrowings under the Master Shelf
Agreement are guaranteed and secured via a pledge of the stock of some of our
subsidiaries.

    In October 2001, we have principal payments totaling $33.3 million due under
the Master Shelf Agreement. We expect to use funds available under the Revolving
Credit Facility to make these payments.

    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 maintenance covenants which include limitations on debt
incurrence, restricted payments, liens and sales of assets. The Subordinated
Notes are unsecured and are guaranteed on a subordinated basis by some of our
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, 2001. Taking into account all the covenants contained in
these agreements, we had approximately $250 million of available borrowing
capacity at June 30, 2001.

                                       19
<PAGE>

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
        ----------------------------------------------------------

Risk Management Activities

    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
hedging fixed price purchase and sale commitments, preserving the value of
storage inventories, reducing exposure to physical market price volatility and
providing risk management services to a variety of customers.

    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 objectives.
These instruments allow us to preserve value and protect margins because
corresponding losses or gains in the value of the financial instruments offset
gains or losses in the physical market.

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

    We enter into futures transactions on the New York Mercantile Exchange, or
NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with
various counter parties, consisting primarily of financial institutions and
other natural gas companies. We conduct our standard credit review of OTC
counter parties and have agreements with 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.

    For the remaining two quarters of 2001, we have entered into hedging
positions for approximately 80,000 MMbtus per day of our equity gas volumes at
an average of $4.36 per MMbtu. These positions represent approximately 70
percent of our projected equity gas volumes in 2001. For 2002, we have hedged
approximately 80,000 MMbtus per day, or 57 percent of our projected 2002 equity
gas production, with collar structures providing for an average minimum price of
$3.81 per MMbtu and an average maximum price of $5.87 per MMbtu. These prices
are NYMEX-equivalents.

    As of June 30, 2001, we had purchased puts for 125,000 barrels per month,
for the remainder of 2001, of NYMEX monthly average settlement of $23.96 per
barrel to hedge a portion of our equity production of natural gasoline,
condensates, butanes and crude oil .

    As of June 30, 2001, we had purchased puts for 125,000 barrels per month,
for the remainder of 2001, of OPIS Mt. Belvieu monthly average settlement of
$.434 per gallon to hedge a portion of our equity production of propane for
2001.

    As of June 30, 2001, we had purchased puts for 60,000 barrels per month, for
the remainder of 2001, of OPIS Mt. Belvieu monthly average settlement of $.3175
per gallon of purity ethane to hedge a portion of our equity production of
ethane for 2001.

    As of June 30, 2001, we did not hold any crude oil or NGL futures, swaps or
options for settlement beyond 2001.

    We enter into speculative futures, swap and option trades on a very limited
basis for purposes that include testing of hedging techniques. Our policies
contain strict guidelines for such trading including predetermined stop-loss
requirements and

                                       20
<PAGE>

net open positions limits. Speculative futures, swap and option positions are
marked-to-market at the end of each accounting period and any gain or loss is
recognized in income for that period. Net gains or losses from such speculative
activities for the quarters ended June 30, 2001 and 2000 were not material.

    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, 2001, the net notional
value of such contracts was approximately $18.8 million in Canadian dollars,
which approximates its fair market value.

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

    Of the $22.5 million decrease to Accumulated other comprehensive income
resulting from the January 1, 2001 adoption of SFAS 133, $17.1 million was
reversed in the first six months of 2001 with gains and losses from the
underlying transactions recognized through operating income. An additional $4.9
million of this transition entry is currently anticipated to be recognized
through operating income in the remaining two quarters of 2001.

    The non-cash impact to our results of operations in the first six months of
2001 resulting from the adoption of mark-to-market accounting for our marketing
activities resulted in additional pre-tax income of $2.2 million.

                                       21
<PAGE>

Principal Facilities

    The following tables provide information concerning our principal facilities
at June 30, 2001. We also own and operate several smaller treating, processing
and transmission facilities located in the same areas as our other facilities.

<TABLE>
<CAPTION>
                                                                                   Average for the Six Months Ended
                                                                                              June 30, 2001
                                                      Gas           Gas       ---------------------------------------------
                                                   Gathering    Throughput         Gas             Gas              NGL
                                      Year Placed   System       Capacity      Throughput      Production       Production
          Facilities (1)              In Service   Miles (2)   (MMcf/D) (3)   (MMcf/D) (4)    (MMcf/D) (5)     (MGal/D) (5)
------------------------------------  ----------   ---------   ------------   ------------    ------------     ------------
<S>                                   <C>          <C>         <C>            <C>             <C>              <C>
 Texas
   Gomez Treating....................      1971         385          280           104               96                -
   Midkiff/Benedum...................      1955       2,188          165           146               95              876
   Mitchell Puckett Gathering........      1972          91          120            79               51                -
Louisiana
   Toca (7)(8).......................      1958           -          160           115              111               92
Wyoming
   Coal Bed Methane
     Gathering.......................      1990       1,100          223           261              242                -
   Fort Union Gas Gathering .........      1999         106          450           277              277                -
   Granger (7)(9)(10)................      1987         494          235           151              129              283
   Hilight Complex (7)...............      1969         626           80            15               11               57
   Kitty/Amos Draw (7)...............      1969         314           17             9                6               37
   Lincoln Road (10) ................      1988         149           50            18               16               30
   Newcastle (7).....................      1981         146            5             3                2               18
   Red Desert (7)....................      1979         111           42            14               13               25
   Reno Junction (9).................      1991           -            -             -                -               94
Oklahoma
   Chaney Dell ......................      1966       2,066          180            70               57              113
   Westana ..........................      1986         965           45            61               54               33
 New Mexico
   San Juan River (6)................      1955         140           60            26               21               15
 Utah
   Four Corners Gathering............      1988         104           15             2                2                5
                                                    -------      -------        ------           ------           ------
     Total...........................                 8,985        2,127         1,351            1,183            1,678
                                                    =======      =======        ======           ======           ======

<CAPTION>
                                                                   Average for the Six Months Ended
                                                                            June 30, 2001
                                                                   --------------------------------
                                                                     Pipeline             Gas
                                      Year Placed    Transmission    Capacity       Throughput
    Transmission Facilities (1)       In Service       Miles (2)   (MMcf/D) (2)     (MMcf/D) (4)
--------------------------------      ----------   --------------  ------------     ------------
<S>                                   <C>          <C>             <C>              <C>
MIGC (11)(13)....................          1970            245           147               184
MGTC (12)........................          1963            252            18                11
                                                       -------         -----           -------
   Total.........................                          497           165               195
                                                       =======         =====           =======
</TABLE>


Footnotes on following page.

                                       22
<PAGE>

(1)    Our interest in all facilities is 100% except for Midkiff/Benedum (73%),
       Newcastle (50%) and Fort Union Gas Gathering (13%). We operate all
       facilities and all data includes our interests and the interests of other
       joint interest owners and producers of gas volumes dedicated to the
       facility. Unless otherwise indicated, all facilities shown in the table
       are gathering and processing facilities.
(2)    Gas gathering system miles, interconnect and transmission miles, and
       pipeline capacity are as of June 30, 2001.
(3)    Gas throughput capacity is as of June 30, 2001 and represents capacity in
       accordance with design specifications unless other constraints exist,
       including permitting or field compression limits.
(4)    Aggregate wellhead natural gas volumes collected by a gathering system or
       volumes transported by a pipeline.
(5)    Volumes of gas and NGLs are allocated to a facility when a well is
       connected to that facility; volumes exclude NGLs fractionated for third
       parties.
(6)    Sour gas facility (capable of processing or treating gas containing
       hydrogen sulfide and/or carbon dioxide).
(7)    Fractionation facility (capable of fractionating raw NGLs into end-use
       products).
(8)    Straddle plant, or a plant located near a transmission pipeline that
       processes gas dedicated to or gathered by a pipeline company or another
       third party.
(9)    NGL production includes conversion of third-party feedstock to iso-
       butane.
(10)   We are currently processing all gas gathered through the Lincoln Road
       gathering system at our Granger facility.
(11)   MIGC is an interstate pipeline located in Wyoming and is regulated by the
       Federal Energy Regulatory Commission.
(12)   MGTC is a public utility located in Wyoming and is regulated by the
       Wyoming Public Service Commission.
(13)   Pipeline capacity represents capacity at the Powder River junction only
       and does not include northern delivery points.

                                       23
<PAGE>

PART II - OTHER INFORMATION

Item 1.   Legal Proceedings
          -----------------

     Western Gas Resources, Inc., Mountain Gas Resources, Inc., v. R.I.S.
Resources International Corporation, a British Columbia , Canada corporation;
RIS Resources (USA) Inc., a Texas Corporation, United States District Court,
Colorado, Civil Action No. 00-S-599. As previously disclosed, our subsidiary
Mountain Gas was a defendant in prior litigation, styled as McMurry Oil Company,
et al. v. TBI Exploration, Inc., Mountain Gas Resources, Inc. and Wildhorse
Energy Partners, LLC, District Court, Ninth Judicial District, Sublette County,
Wyoming, Civil Action No. 5882, which was settled on all issues for
substantially less than the amount claimed. Western and Mountain Gas were
seeking reimbursement from RIS Resources, (USA), Inc., Mountain Gas' joint
venture partner, for 50% of the settlement amount which was paid in full by
Mountain Gas. In May 2001, we acquired RIS' 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 this litigation.

     Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court,
Denver County, Colorado, Civil Action No. 00-CV-1433. As previously disclosed,
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 has been settled
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. Amerada Hess sought a motion to dismiss, which was
denied. We have amended our original complaint and requested a jury trial in
this case. The parties are proceeding with discovery.

     Barrett Resources Corporation and Lance Oil & Gas Company, Inc.,
(collectively Plaintiffs) v. Westport Oil and Gas Company, Inc., (Defendant)
Civil Action No. 00CV6973, District Court, City and County of Denver, Colorado.
On September 15, 2000 Plaintiffs filed a complaint for damages and declaratory
relief related to a dispute arising under a Farmout Agreement between the
parties dated September 26, 1995, as amended. The dispute centers on Plaintiffs'
alleged delay of drilling of wells on a portion of the acreage covered by the
Farmout Agreement. In October 2000, Defendant counterclaimed that the Farmout
Agreement was terminated due to Plaintiffs' alleged delay of drilling. In July
2001, Plaintiffs notified Defendant of the commencement of drilling eleven wells
on the acreage covered by the Farmout Agreement. In August 2001, Defendant filed
supplemental counterclaims which included claims for trespass, conversion,
accounting and constructive trust on the eleven wells drilled by Plaintiff and
compensatory and exemplary damages in connection with these wells. A trial for
this case is set for December 3, 2001 and the parties are currently proceeding
with discovery. We intend to vigorously defend against the counterclaims but
cannot express an opinion as to the outcome of this litigation. We believe that
any unfavorable outcome will not have a material adverse effect on our financial
condition.

     Other. We are involved in various other litigation and administrative
proceedings arising in the normal course of our 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.

                                       24
<PAGE>

Item 4.   Submission of Matters to a Vote of Security Holders
          ---------------------------------------------------

The following matters were voted on at our Annual Meeting of Stockholders held
on May 18, 2001:

   Walter L. Stonehocker, Dean Phillips, Bill M. Sanderson, and James A. Senty
were elected as Class Three Directors to serve until their terms expire in 2004
and until their successors have been elected. A total of 25,992,081, 26,071,914,
26,022,139 and 26,072,061 shares, respectively, were voted for and 328,033,
248,200, 297,975, and 248,053 shares respectively, were withheld for Walter L.
Stonehocker, Dean Phillips, Bill M. Sanderson, and James A. Senty.


Item 6.   Exhibits and Reports on Form 8-K
          --------------------------------

(a)  Exhibits:

          3.3   Amended and Restated Bylaws of Western Gas Resources, Inc.
                adopted by the Board of Directors on July 13, 2001.

          10.7  Form of revised Employment Agreement with exhibit thereto by and
                between Western Gas Resources, Inc. and its Executive Officers
                dated June 14, 2001.

          10.27 Amendment to Employment Agreement by and between Western Gas
                Resources, Inc. and Lanny F. Outlaw its Chief Executive Officer
                and President dated May 18, 2001.


(b)  Reports on Form 8-K:

                None

                                       25
<PAGE>

SIGNATURES

    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.

                                   WESTERN GAS RESOURCES, INC.
                                   ---------------------------
                                   (Registrant)


Date: August 13, 2001              By: /s/ LANNY F. OUTLAW
                                       -------------------------------------
                                       Lanny F. Outlaw
                                       Chief Executive Officer and President


Date: August 13, 2001              By: /s/ WILLIAM J. KRYSIAK
                                       -------------------------------------
                                       William J. Krysiak
                                       Vice President - Finance
                                       (Principal Financial and Accounting
                                       Officer)

                                       26
<PAGE>

SIGNATURES

    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.

                                     WESTERN GAS RESOURCES, INC.
                                     ---------------------------
                                     (Registrant)


Date: August 13, 2001              By:
                                      -------------------------------
                                      Lanny F. Outlaw
                                      Chief Executive Officer and President


Date: August 13, 2001              By:
                                      -------------------------------
                                      William J. Krysiak
                                      Vice President - Finance
                                      (Principal Financial and Accounting
                                      Officer)

                                       27