<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 MARCH 31, 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 May 1, 2001, there were 32,497,723 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 - March 31, 2001 and December 31, 2000................     3

             Consolidated Statement of Cash Flows - Three Months Ended March 31, 2001
             and 2000.........................................................................     4

             Consolidated Statement of Operations - Three Months Ended March 31, 2001 and 2000     5

             Consolidated Statement of Changes in Stockholders' Equity - Three Months Ended
             March 31, 2001...................................................................     6

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

  Item 2.    Management's Discussion and Analysis of Financial Condition and Results of
             Operations.......................................................................    11

  Item 3.    Quantitative and Qualitative Disclosures about Market Risk.......................    18

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

  Item 1.    Legal Proceedings................................................................    22

  Item 4.    Submission of matters to a vote of security holders..............................    23

  Item 6.    Exhibits and Reports on Form 8-K.................................................    23

Signatures....................................................................................    24

</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>
                                                                                               March 31,   December 31,
  ASSETS                                                                                            2001           2000
  ------                                                                                      ----------     ----------
                                                                                              (unaudited)
<S>                                                                                           <C>          <C>
Current assets:
 Cash and cash equivalents..................................................................  $   74,387     $   12,927
 Trade accounts receivable, net.............................................................     356,393        546,791
 Product inventory..........................................................................      14,364         44,822
 Parts inventory............................................................................       3,102          3,489
 Assets from price risk management activities...............................................      31,156              -
 Assets held for sale.......................................................................           -         25,001
 Other......................................................................................       2,953          2,654
                                                                                              ----------     ----------
   Total current assets.....................................................................     482,355        635,684
                                                                                              ----------     ----------
Property and equipment:
 Gas gathering, processing, storage and transportation......................................     862,690        856,982
 Oil and gas properties and equipment (successful efforts method)...........................     156,864        139,084
 Construction in progress...................................................................      57,457         58,319
                                                                                              ----------     ----------
                                                                                               1,077,011      1,054,385
 Less:  Accumulated depreciation, depletion and amortization................................    (320,096)      (306,651)
                                                                                              ----------     ----------
   Total property and equipment, net........................................................     756,915        747,734
                                                                                              ----------     ----------
Other assets:
 Gas purchase contracts (net of accumulated amortization of $33,840 and
   $33,357, respectively)...................................................................      34,316         34,798
 Assets from price risk management activities...............................................         670              -
 Other......................................................................................      14,327         13,206
                                                                                              ----------     ----------
 Total other assets.........................................................................      49,313         48,004
                                                                                              ----------     ----------
TOTAL ASSETS................................................................................  $1,288,583     $1,431,422
                                                                                              ==========     ==========
   LIABILITIES AND STOCKHOLDERS' EQUITY
   ------------------------------------
Current liabilities:
 Accounts payable...........................................................................  $  401,309     $  581,563
 Accrued expenses...........................................................................      35,276         25,094
 Liabilities from price risk management activities..........................................      39,728              -
 Dividends payable..........................................................................       4,209          4,205
                                                                                              ----------     ----------
   Total current liabilities................................................................     480,522        610,862
Long-term debt..............................................................................     305,000        358,700
Liabilities from price risk management activities...........................................         385              -
Other long-term liabilities.................................................................       2,559          2,646
Deferred income taxes payable, net..........................................................      79,550         67,680
                                                                                              ----------     ----------
Total liabilities...........................................................................     868,016      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; 32,497,723 and
    32,361,131 shares issued, respectively..................................................       3,275          3,265
 Treasury stock, at cost; 25,016 common shares and 44,290 shares of $2.28 cumulative
    preferred stock in treasury.............................................................      (2,003)        (1,778)
 Additional paid-in capital.................................................................     401,102        400,157
 Retained earnings (deficit)................................................................      24,561        (11,820)
 Accumulated other comprehensive income.....................................................      (5,996)         2,178
 Notes receivable from key employees secured by common stock................................        (884)          (884)
                                                                                              ----------     ----------
   Total stockholders' equity...............................................................     420,567        391,534
                                                                                              ----------     ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................................................  $1,288,583     $1,431,422
                                                                                              ==========     ==========
     The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>

                                       3
<PAGE>

                          WESTERN GAS RESOURCES, INC.
                     CONSOLIDATED STATEMENT OF CASH FLOWS
                                  (Unaudited)
                            (Dollars in thousands)
<TABLE>
<CAPTION>
                                                                                Three Months Ended
                                                                                   March 31,
                                                                              ---------------------
                                                                                 2001        2000
                                                                              ---------   ---------
<S>                                                                           <C>         <C>
Reconciliation of net income to net cash provided by operating activities:
Net income..................................................................  $  40,590   $  13,006
Add income items that do not affect cash:
 Depreciation, depletion and amortization...................................     14,478      13,309
 Gain on the sale of property and equipment.................................    (11,223)     (5,299)
 Deferred income taxes......................................................     16,719       7,441
 Non-cash change in fair value of derivatives...............................     (5,049)          -
 Other non-cash items, net..................................................          8         929
                                                                              ---------   ---------
                                                                                 55,523      29,386
                                                                              ---------   ---------

Adjustments to working capital to arrive at net cash provided by
 operating activities:
 (Increase) decrease in trade accounts receivable...........................    190,454     (31,234)
 Decrease in product inventory..............................................     30,458      22,762
 Decrease in parts inventory................................................        387       1,066
 (Increase) decrease in other current assets................................       (299)      7,937
 Decrease in other assets and liabilities, net..............................      8,076          37
 Decrease in accounts payable...............................................   (180,254)     (5,614)
 (Increase) decrease in accrued expenses....................................      2,199     (14,975)
                                                                              ---------   ---------

Net cash provided by operating activities...................................    106,544       9,365
                                                                              ---------   ---------

Cash flows from investing activities:
 Purchases of property and equipment........................................    (25,908)    (28,498)
 Proceeds from the dispositions of property and equipment...................     38,075      15,057
 Contributions to equity investees..........................................       (169)          -
                                                                              ---------   ---------

Net cash provided by (used in) investing activities.........................     11,998     (13,441)
                                                                              ---------   ---------

Cash flows from financing activities:
 Proceeds from exercise of common stock options.............................        955          71
 Repurchase of $2.28 cumulative preferred stock.............................       (129)          -
 Payments on revolving credit facility......................................   (301,953)   (293,286)
 Borrowings under revolving credit facility.................................    248,250     291,350
 Payments on notes..........................................................          -           -
 Dividends paid.............................................................     (4,205)     (4,217)
                                                                              ---------   ---------

Net cash used in financing activities.......................................    (57,082)     (6,082)
                                                                              ---------   ---------
Net increase (decrease) in cash and cash equivalents........................     61,460     (10,158)
Cash and cash equivalents at beginning of period............................     12,927      14,062
                                                                              ---------   ---------
Cash and cash equivalents at end of period..................................  $  74,387   $   3,904
                                                                              =========   =========
</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
                                                                                 March 31,
                                                                         --------------------------
                                                                             2001          2000
                                                                         -----------   -----------
<S>                                                                      <C>           <C>
Revenues:
 Sale of gas...........................................................  $ 1,044,876   $   413,816
 Sale of natural gas liquids...........................................      129,477       135,388
 Processing, transportation and storage revenue........................       16,036        13,885
 Unrealized gain on marketing activities...............................        5,049             -
 Other, net............................................................        1,838         2,063
                                                                         -----------   -----------

   Total revenues......................................................    1,197,276       565,152
                                                                         -----------   -----------

Costs and expenses:
 Product purchases.....................................................    1,086,600       501,143
 Plant operating expense...............................................       17,037        15,262
 Oil and gas exploration and production expense........................        9,605         4,146
 Depreciation, depletion and amortization..............................       14,478        13,309
 Gain on sale of assets................................................      (11,223)       (5,299)
 Selling and administrative expense....................................        8,479         7,389
 Interest expense......................................................        6,829         8,218
                                                                         -----------   -----------

   Total costs and expenses............................................    1,131,805       544,168
                                                                         -----------   -----------

Income before taxes....................................................       65,471        20,984

Provision for income taxes:
 Current...............................................................        8,162           537
 Deferred..............................................................       16,719         7,441
                                                                         -----------   -----------

     Total provision for income taxes..................................       24,881         7,978
                                                                         -----------   -----------

Net income.............................................................       40,590        13,006

Preferred stock requirements...........................................       (2,584)       (2,610)
                                                                         -----------   -----------

Income attributable to common stock....................................  $    38,006   $    10,396
                                                                         ===========   ===========

Earnings per share of common stock.....................................        $1.17          $.32
                                                                         ===========   ===========

Weighted average shares of common stock outstanding....................   32,405,044    32,165,868
                                                                         ===========   ===========

Income attributable to common stock-assuming dilution..................  $    39,817   $    10,396
                                                                         ===========   ===========

Earnings per share of common stock-assuming dilution...................        $1.08          $.32
                                                                         ===========   ===========

Weighted average shares of common stock outstanding-assuming dilution..   36,757,118    32,459,209
                                                                         ===========   ===========

</TABLE>
   The accompanying notes are an integral part of the consolidated financial
                                  statements.

                                       5
<PAGE>

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

<TABLE>
<CAPTION>

                                           Shares of
                              Shares of      $2.28      $2.625                                            $2.625
                                $2.28      Cumulative  Cumulative                Shares       $2.28      Cumulative
                              Cumulative   Preferred  Convertible   Shares     of Common   Cumulative   Convertible
                              Preferred    Stock in    Preferred   of Common   Stock in    Preferred     Preferred    Common
                                Stock      Treasury      Stock       Stock      Treasury      Stock         Stock      Stock
                              ----------  ----------  ----------- ----------  ----------   ---------    -----------  --------
<S>                           <C>         <C>         <C>         <C>         <C>          <C>          <C>          <C>
Balance at December 31,
 2000......................   1,400,000      39,190    2,760,000  32,361,131    25,016         140          276         3,265
Comprehensive income:
 Net income, three months
  ended
  March 31, 2001...........           -           -            -           -         -           -            -             -
 Translation adjustments...           -           -            -           -         -           -            -             -
 Cumulative change for
  accounting principle
  January 1, 2001..........           -           -            -           -         -           -            -             -
 Reclassification adjustment
  for settled contracts....           -           -            -           -         -           -            -             -
 Changes in fair value of
  outstanding hedging
  positions................           -           -            -           -         -           -            -             -

 Total comprehensive
  income, net of tax.......

Stock options exercised....           -           -            -     136,592         -           -            -            10
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 March 31, 2001..   1,400,000      44,290    2,760,000  32,497,723    25,016  $      140  $       276      $  3,275
                             ==========  ==========  ===========  ==========  ========  ==========  ===========      ========
</TABLE>

<TABLE>
<CAPTION>
                                                                 Accumulated
                                                                   Other         Notes     Total
                                        Additional   Retained   Comprehensive  Receivable  Stock-
                             Treasury   Paid-In      (Deficit)     Income      from Key    holders'
                             Stock       Capital     Earnings    Net of Tax    Employees   Equity
                             --------   ----------   --------   -------------  ----------  --------
<S>                          <C>        <C>          <C>        <C>            <C>         <C>
Balance at December 31,
 2000......................   (1,778)     400,157    (11,820)           2,178        (884)  391,534
Comprehensive income:
 Net income, three months
  ended
  March 31, 2001...........        -            -     40,590                -           -    40,590
 Translation adjustments...        -            -          -              256           -       256
 Cumulative change for
  accounting principle
  January 1, 2001..........        -            -          -          (22,527)          -   (22,527)
 Reclassification adjustment
  for settled contracts....        -            -          -           13,429           -    13,429
 Changes in fair value of
  outstanding hedging
  positions................        -            -          -              668           -       668
                                                                                           --------
 Total comprehensive
  income, net of tax.......                                                                  32,416
                                                                                           --------

Stock options exercised....        -          945          -                -           -       955
Tax benefit related to
 stock options.............        -            -          -                -           -        -
Loans forgiven.............        -            -          -                -           -        -
Dividends declared on
 common stock..............        -            -     (1,625)               -           -    (1,625)
Dividends declared on
 $2.28 cumulative
 preferred stock...........        -            -       (773)               -           -      (773)
Dividends declared on
 $2.625 cumulative
 convertible preferred
  stock....................        -            -     (1,811)               -           -    (1,811)
Repurchase of $2.28
 cumulative preferred
 stock.....................     (129)           -          -                -           -      (129)
                             --------   ----------   --------   -------------  ----------  --------

Balance at March 31, 2001..   (1,907)   $ 401,102     $24,561   $     (5,996)  $     (884) $420,567
                             ========   ==========   ========   =============  ==========  ========
</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 March 31, 2001 and for the
three month periods ended March 31, 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 months ended March 31, 2001
are not necessarily indicative of the results of operations expected for the
year ended December 31, 2001.

  Prior period 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 for each of the three-month
periods ended March 31, 2001 and 2000, respectively.  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 4,352,074 and 293,341 for the
three-month periods ended March 31, 2001and 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.  We
acquired the pipeline through the exercise of an option in a transaction, which
closed simultaneously with the sale of WGR-California.  We recognized a pre-tax
gain on the sale of approximately $5.4 million in the first quarter of 2000.

  The proceeds from these sales were initially 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.


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.

                                       7
<PAGE>

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, $14.1 million was
reversed in the first quarter of 2001 with gains and losses from the underlying
transactions recognized through Total revenues.  An additional $7.1million of
this transition entry is currently anticipated to be recognized through
Total revenues in the remaining three quarters of 2001.

  The non-cash impact to our results of operations in the first quarter of 2001
resulting from the adoption of mark-to-market accounting for our marketing
activities resulted in additional pre-tax income of $5.0 million.

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
1/100th 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 $4.2 million and $4.7 million for the three months ended
March 31, 2001 and 2000, respectively.

  No income taxes were paid during the three months ended March 31, 2001 or the
three months ended March 31, 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 facilities are
located.  The Marketing segment sells the majority of the production from these
properties.

  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 $(14.5) million and
$(3.1) million for the quarters ended March 31, 2001 and March 31, 2000,
respectively.

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

                                       8
<PAGE>

  The following table sets forth our segment information as of and for the
quarters ended March 31, 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 March 31, 2001
Revenues from unaffiliated customers......    $ 14,035    $    721   $1,209,769   $ 2,675     $   282  $       -   $1,227,482
Interest income...........................           -           -            -         -       5,086     (4,802)         284
Other, net................................           4          (1)     (31,872)        2       1,377          -      (30,490)
Intersegment sales........................     318,073      52,150       11,486     4,267          14   (385,990)           -
                                              --------    --------   ----------   -------     -------  ---------   ----------
Total revenues............................     332,112      52,870    1,189,383     6,944       6,759   (390,792)   1,197,276
                                              --------    --------   ----------   -------     -------  ---------   ----------
Product purchases.........................     272,839       2,645    1,188,165      (434)         13   (376,628)   1,086,600
Plant operating expense...................      15,320          30           39     2,094         375       (821)      17,037
Oil and gas exploration
    and production expense................           -      17,054            -         -           -     (7,449)       9,605
                                              --------    --------   ----------   -------     -------  ---------   ----------
Operating profit..........................    $ 43,953    $ 33,141   $    1,179   $ 5,284     $ 6,371  $  (5,894)  $   84,034
                                              ========    ========   ==========   =======     =======  =========   ==========

Depreciation, depletion and amortization..       9,500       3,067           40       415       1,456          -       14,478
Interest expense..........................                                                                              6,829
Gain on sale of assets....................                                                                            (11,223)
Selling and administrative expense........                                                                              8,479
                                                                                                                   ----------
Income before income taxes................                                                                         $   65,471
                                                                                                                   ==========

Identifiable assets.......................    $563,850    $141,430   $       57   $46,808     $55,384  $       -   $  807,529
                                              ========    ========   ==========   =======     =======  =========   ==========

</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 March 31, 2000
Revenues from unaffiliated customers......    $ 11,406     $    986   $551,322   $ 2,378    $    26   $      (8)  $566,110
Interest income...........................          33            2         24         -      5,838      (5,668)       229
Other, net................................         (20)           -     (2,203)        -      1,036           -     (1,187)
Intersegment sales........................     134,342       10,304     26,333     4,404          4    (175,387)         -
                                              --------     --------   --------   -------    -------   ---------   --------
Total revenues............................     145,761       11,292    575,476     6,782      6,904    (181,063)   565,152
                                              --------     --------   --------   -------    -------   ---------   --------
Product purchases.........................     103,008          504    572,687         -        (25)   (175,031)   501,143
Plant operating expense...................      13,062           17          -     2,268        256        (341)    15,262
Oil and gas exploration
    and production expense................           -        4,146          -         -          -           -      4,146
                                              --------     --------   --------   -------    -------   ---------   --------
Operating profit..........................    $ 29,691     $  6,625   $  2,789   $ 4,514    $ 6,673   $  (5,691)  $ 44,601
                                              ========     ========   ========   =======    =======   =========   ========

Depreciation, depletion and amortization..       8,571        2,889         40       424      1,385           -     13,309
Interest expense..........................                                                                           8,218
Gain on sale of assets....................                                                                          (5,299)
Selling and administrative expense........                                                                           7,389
                                                                                                                  --------
Income before income taxes................                                                                        $ 20,984
                                                                                                                  ========

Identifiable assets.......................    $547,611     $101,802   $     75   $47,213    $37,710   $       -   $734,411
                                              ========     ========   ========   =======    =======   =========   ========

</TABLE>

                                       9
<PAGE>

LEGAL PROCEEDINGS

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

                                       10
<PAGE>

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

  The following discussion and analysis relates to factors that have affected
our consolidated financial condition and results of operations for the three
months ended March 31, 2001 and 2000.   Prior period 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 months ended March 31, 2001 compared to the three months ended March 31,
2000
(Dollars in thousands, except per share amounts and operating data).
<TABLE>
<CAPTION>

                                               Three Months Ended
                                                    March 31,
                                              --------------------  Percent
                                                 2001       2000     Change
                                              ----------  --------  -------
<S>                                           <C>         <C>       <C>
Financial results:
Revenues....................................  $1,197,276  $565,152      112
Gross profit................................      80,779    36,591      121
Net income..................................      40,590    13,006      212
Earnings per share of common stock..........        1.17       .32      266
Earnings per share of common stock-diluted..        1.08       .32      238
Net cash provided by operating activities...  $  106,544  $  9,365    1,038

Operating data:
Average gas sales (MMcf/D)..................       1,665     1,800       (8)
Average NGL sales (MGal/D)..................       2,230     3,125      (29)
Average gas prices ($/Mcf)..................  $     6.97  $   2.52      177
Average NGL prices ($/Gal)..................  $      .63  $    .48       31
</TABLE>

  Net income increased $27.6 million for the three months ended March 31, 2001
compared to the same period in 2000.  The increase in net income was primarily
attributable to significantly higher gas and NGL prices in the first quarter of
2001 compared to the same period last year, increased production from the Powder
River coal bed methane development, improved marketing margins and a net
increase in after-tax gain of $3.2 million from the sale of assets in the first
quarter of 2001 as compared to the same period in 2000. These increases were
partially offset by a net increase in after-tax losses on hedging activities on
our equity gas and NGLs of $7.3 million in the first quarter of 2001 as compared
to the same period in 2000.

  Revenues from the sale of gas increased $632.0 million to $1,044.9 million for
the three months ended March  31, 2001 compared to the same period in 2000.
This increase was due to an improvement in product prices in 2001 which more
than offset a reduction in sales volume. Average gas prices realized by us
increased $4.45 per Mcf to $6.97 per Mcf for the quarter ended March 31, 2001
compared to the same period in 2000. Average gas sales volumes decreased 135
MMcf per day to 1,665 MMcf per day for the quarter ended March 31, 2001 compared
to the same period in 2000. This decrease was due to an intentional reduction by
us in our third-party transactions in the first quarter of 2001 due to the high
price of natural gas and its impact on the credit exposure to our individual
counter-parties.

  Revenues from the sale of NGLs decreased approximately $5.9 million for the
three months ended March 31, 2001 compared to the same period in 2000.  This
decrease is primarily due to a reduction in the sale of  third-party product
which was substantially offset by an improvement in product prices.  Also we
rejected ethane at our facilities for a portion of the first quarter of 2001
which contributed to the decrease in sales volume.  We reject ethane when it is
more profitable for us to sell this product as a component of the gas stream
rather than as an NGL.  Average NGL prices realized by us increased $.15 per
gallon to $.63 per gallon for the three months ended March 31, 2001 compared to
the same period in 2000.   Average NGL sales volumes decreased 895 MGal per day
to 2,230 MGal per day for the three months ended March 31, 2001 compared to the
same period in 2000.

                                       11
<PAGE>

  Product purchases increased by $585.5 million for the quarter ended March 31,
2001 compared to the same period in 2000 as a result of the increase in
commodity prices.  Overall, combined product purchases as a percentage of sales
of all products increased to 98% in the first quarter of 2001 from 91% in the
first quarter of 2000.  The prices received and paid for the sale and purchase
of  third-party product increased with commodity prices; however, the net margin
received from this activity did not increase proportionally.

  Marketing margins on residue gas averaged $.06 per Mcf in the first quarter of
2001.  This represents a significant increase as compared to the margin realized
during the same period during 2000 of $.02 per Mcf.  The increase in margin in
the first quarter of 2001 is primarily due to our adoption of mark-to-market
accounting.  Under this method of accounting, the margin to be realized over the
term of the sales agreement 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 in marketing
activities.  Also contributing to the increase in the margin realized in the
first quarter of 2001 was the effect of the current volatile market conditions
and our ability to benefit from these conditions through our transportation
arrangements.  Marketing margins on NGLs remained relatively constant at
approximately $.008 per gallon for each of the quarters ended March 31, 2001 and
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.

  Oil and gas exploration and production expenses increased $5.6 million for the
quarter ended March 31, 2001 compared to the same period in 2000.  These
increases are due to increased production taxes and lease operating expenses
resulting from our increased drilling and production activities in the Powder
River coal bed methane development.

  In the first quarter of 2001, we realized a net pre-tax gain of $11.2 million
on the sale of our wholly-owned subsidiary, Pinnacle Gas Treating, Inc.  In the
first quarter of 2000, we realized a net pre-tax gain of $5.3 million on the
sale of our California subsidiary, Western Gas Resources - California, Inc.

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 for $38.0 million.  The only asset of this
subsidiary was a 300 MMcf per day treating facility and 86 miles of associated
gathering 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 of the
outstanding stock of our wholly-owned subsidiary, WGR-California for $14.9
million.  The only asset of this subsidiary was a 162-mile pipeline in the
Sacramento basin of California.  We acquired the pipeline through the exercise
of an option in a transaction that 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 initially 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 were reflected in revenues in Other, net on the Consolidated
Statement of Operations.  Since March 2000, the results of these operations have
been  fully consolidated and are included in Revenues and Costs and expenses.
Additionally, in March 2000, our investment in the Westana Gathering Company was
reclassed from Other assets to Property and equipment.

Business Strategy

  In 1998 and 1999, as oil and gas prices were approaching historical lows, our
activities were focused on consolidating our businesses in our core operating
regions and reducing our outstanding debt.  Improved product prices throughout
2000 and continuing into 2001 along with our improved financial position will
allow 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.

                                       12
<PAGE>

  With our improved financial position, in 2001, we will actively evaluate
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 $136.4 million. This
includes approximately $71.8 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 quarter of 2001, our capital expenditures
totaled $26.1 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 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 and newly dedicated 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, 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 that 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 530,000 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. These properties have an
additional 58Bcf of proved developed and undeveloped reserves. This represents
an increase of approximately 50% in our proved reserves from December 31, 1999.
We also estimate a net total of 1.9 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 to continue its efforts 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 volumes of natural gas produced from our reserves, the margin on
third-party product purchased for resale, as well as the timely collection of
our receivables will affect net cash provided by operating activities in the
future.  Our future growth will be dependent upon obtaining additions to
dedicated plant reserves, increasing our production, completing acquisitions,
developing new projects, operating our facilities efficiently and obtaining
financing at favorable terms.

  We believe that our cash and cash equivalents, 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, make any scheduled debt principal payments and

                                       13
<PAGE>

make any scheduled dividend payments on our preferred stock. 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 additional capital is in
some cases 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 and cash equivalents, cash provided by operating
activities and amounts available under our Revolving Credit Facility will be
sufficient to meet our debt service and preferred stock dividend requirements
for the remainder of 2001, and in 2002 and 2003.

  While several 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, greater demand for natural gas,
improved technology, e.g., 3-D seismic, well fracturing and horizontal drilling,
and increased pipeline capacity from the Rocky Mountain region have stimulated
drilling in many of our operating areas.  The overall level of drilling will
depend upon, among other factors, the prices for oil and gas, the drilling
budgets of third-party producers, the energy and environmental policy and
regulation by governmental agencies and the availability of foreign oil and gas,
none of which is within our control. There is no assurance that we will continue
to be successful in replacing the dedicated reserves processed at our
facilities.

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

  Our sources and uses of funds for the quarter ended March 31, 2001 are
summarized as follows (dollars in thousands):
<TABLE>
<CAPTION>

Sources of funds:
<S>                                                                     <C>
     Borrowings under revolving credit facility.......................  $248,250
     Proceeds from the dispositions of property and equipment.........    38,075
     Net cash provided by operating activities........................   106,544
     Proceeds from exercise of common stock options...................       955
     Other............................................................         -
                                                                        --------
       Total sources of funds.........................................  $393,824
                                                                        ========
Uses of funds:
     Payments related to long-term debt (including debt issue costs)..  $301,953
     Capital expenditures.............................................    25,908
     Re-purchase of $2.28 Cumulative Perpetual Preferred Stock........       129
     Dividends paid...................................................     4,205
     Contributions to equity investees................................       169
                                                                        --------
       Total uses of funds............................................  $332,364
                                                                        ========
</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
2.4 Bcf at an average cost of $5.03 per Mcf at March 31, 2001 compared to 4.7
Bcf at an average cost of $2.21 per Mcf at March 31, 2000 under storage
contracts at various third-party facilities.  At March 31, 2001, we had hedging
contracts in place for anticipated sales of approximately 2.1 Bcf of stored gas
at a weighted average price of $5.61 per Mcf for the stored inventory.

  We held NGLs in storage under exchange agreements of 5,831MGal, consisting
primarily of propane and normal butane, at an average cost of $.44 per gallon
and 4,700 MGal at an average cost of $.30 per gallon at March 31, 2001 and 2000,
respectively, at various third-party storage facilities.   At March 31, 2001, we
had no significant hedging contracts in place for anticipated sales of stored
NGLs.

Preferred Stock Repurchase Program

  In the first quarter of 2001, we purchased in open market transactions a total
of 5100 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.

                                       14
<PAGE>

Capital Investment Program

  We expect capital expenditures related to existing operations to be
approximately $136.4 million during 2001, consisting of the following: (i)
approximately $71.8 million related to gathering, processing and pipeline
assets, of which $8.5 million is for maintaining existing facilities; (ii)
approximately $56.9 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 49% and 10%, respectively, of the total
2001 budget.  This budget will be increased to provide for acquisitions if
approved by our board of directors.

  As of March 31, 2001, we have expended $26.1 million, consisting of the
following: (i) $7.8 million related to gathering, processing and pipeline
assets, of which $1.3 million is for maintaining existing facilities; (ii) $15.1
million related to exploration and production activities; and (iii) $3.2 million
for miscellaneous items.

  Coal Bed Methane - We continue to develop our Powder River basin coal bed
methane gathering system and our coal seam gas reserves 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 quarter
of 2001, we continued to be the largest producer of natural gas (together with
our partner), the largest gatherer of natural gas and the largest gas
transporter out of the basin.  At March 31, 2001, we held the drilling rights on
approximately 800,000 gross acres, or 530,000 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 December 31, 2000,
we also estimated that there was a net total of 1.6 Tcf of probable reserves on
an unaudited and unrisked basis associated with undeveloped acreage in this
area.  There can be no assurance, however, as to the ultimate recovery of these
probable reserves.  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 320 MMcf. Our average finding and
development costs in this area are estimated to be $.32 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/D at December 31, 1999 to 208 MMcf/D at March 31, 2001. 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 March 31, 2001, we were
gathering 265 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.

  Future drilling on federal acreage will be delayed subject to completion of
the Powder River Basin Oil & Gas Environmental Impact Statement. This study is
anticipated to be completed in the second 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
allow water discharge in the Powder River drainage area in which most of our Big
George prospects are located.  The majority of wells on our acreage producing
from the Wyodak formation drain into the Cheyenne and Belle Fourche drainage
areas. We have water discharge permits in place for approximately 70 percent of
the 840 gross wells currently planned for drilling in 2001.  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.

  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 quarter of 2001,
capital expenditures in this area totaled $12.7 million.

  In December 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/D with expansion capability and in March 2001 it had
throughput of approximately 261 MMcf/D. The header delivers coal bed methane gas
to a treating facility near Glenrock, Wyoming and accesses interstate pipelines
serving gas markets in the Rocky Mountain and Midwest regions of the United
States. The

                                       15
<PAGE>

gathering header and treating system initially went into service in September
1999 and was project financed, requiring a cash investment by us of
approximately $900,000. In conjunction with the project financing, we also
entered into a ten year agreement for firm gathering services on 60 MMcf/D of
capacity at $.14 per Mcf on Fort Union beginning in December 1999. 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/D. 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 an additional 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/D 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/D and processed an average of  181 MMcf/D in the first quarter of
2001.  Our capital budget in this area provides for expenditures of
approximately $13.1 million during 2001.  This capital budget includes
approximately $5.8 million for drilling costs and production equipment and
approximately $7.3 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 quarter of 2001, we expended $4.4 million in this
area.

  Under a 1997 agreement with an active producer in this area, we established a
1.8 million acre area of mutual interest (AMI), in which we participate in
approximately 248,000 gross acres, or approximately 35,400 net acres.
Approximately 4,000 gross acres, or approximately 600 net acres have proven
reserves. We have also entered into agreements with the producer, or its
assigns, for the gathering and processing of natural gas, which may be developed
on 16 prospects within the AMI. Through March 31, 2001, we participated in 20
gross development wells, or 2 net development wells, in the Jonah field of
southwest Wyoming. We did not participate in any exploratory wells in the Hoback
basin during the first quarter of 2001. We expect to participate in the drilling
of 18 gross wells, or 2 net wells in this area during 2001. The average drilling
and completion costs per gross well are approximately $2.4 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. We also
estimate a net total of 278 Bcf of reserves on an unaudited and unrisked basis
associated with undeveloped acreage in this area. There can be no assurance,
however, as to the ultimate recovery of these probable 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 three-year $167 million Revolving Credit Facility, or Tranche B.  At March
31, 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 March 31, 2001,
the annual interest rate payable on any borrowings under this facility would
have been 6.5%. 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 our
significant subsidiaries. We generally utilize excess daily funds to reduce any
outstanding balances on the Revolving Credit Facility and associated interest
expense.

  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 March 31, 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>

                                       16
<PAGE>

  Under our agreement with Prudential, we are required to maintain a current
ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth
equal to the sum of $300 million plus 50% of consolidated net earnings earned
from January 1, 1999 plus 75% of the net proceeds of any equity offerings after
January 1, 1999, a total debt to capitalization ratio of not more than 60%
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 2.75 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
4.50 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 $75.0 million was available at March 31, 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.  Borrowings under the Master Shelf Agreement
are guaranteed and secured via a pledge of the stock of our significant
subsidiaries.

  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
tradable notes under the same terms and conditions.  The Subordinated Notes bear
interest at 10% 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 are being amortized over the term
of the notes.

  Covenant Compliance.   We were in compliance with all covenants in our debt
agreements at March 31, 2001.  Taking into account all the covenants contained
in these agreements, we had approximately $202 million of available borrowing
capacity at March 31, 2001.

                                       17
<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 three quarters of 2001, we have entered into hedging
positions for approximately 50,000 MMbtus per day of its equity gas volumes at
an average of $4.34 per MMbtu.  These positions represent approximately 48
percent of the Western's projected equity gas volumes in 2001.For 2002, Western
has hedged approximately 52,000 MMbtus per day, or 35 percent of its projected
2002 equity gas production, with collar structures providing for an average
minimum price of $3.71 per MMbtu and an average maximum price of $6.32 per
MMbtu.  These prices are NYMEX-equivalents.

  As of March 31, 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 March 31, 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 March 31,2001, 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 March 31, 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 net open positions limits. Speculative futures, swap and option
positions are marked-to-market at the end of each accounting

                                       18
<PAGE>

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 March 31, 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 March 31, 2001, the net notional
value of such contracts was approximately $6.8 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 $1.2 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, $14.1 million was
reversed in the first quarter of 2001 with gains and losses from the underlying
transactions recognized through operating income.  An additional $7.1 million of
this transition entry is currently anticipated to be recognized through
operating income in the remaining three quarters of 2001.

  The non-cash impact to our results of operations in the first quarter of 2001
resulting from the adoption of mark-to-market accounting for our marketing
activities resulted in additional pre-tax income of $5.0 million.

                                       19
<PAGE>

Principal Facilities

  The following tables provide information concerning our principal facilities
at March 31, 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 Quarter Ended
                                                                                           March 31, 2001
                                                     Gas           Gas       -------------------------------------------
                                                  Gathering     Throughput       Gas             Gas            NGL
                                   Year Placed     System        Capacity     Throughput     Production      Production
      Plant 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           100               93             -
  Midkiff/Benedum................         1955         2,188           165           144               95           860
  Mitchell Puckett Gathering.....         1972            91           120            82               54             1
Louisiana
  Toca (7)(8)....................         1958             -           160           120              115            96
Wyoming
  Coal Bed Methane
   Gathering.....................         1990           444           223           252              235             -
  Fort Union Gas Gathering.......         1999           106           450           261              261             -
  Granger (7)(9)(10).............         1987           492           235           149              127           268
  Hilight Complex (7)............         1969           626            80            64               60            67
  Kitty/Amos Draw (7)............         1969           314            17             9                6            37
  Lincoln Road (10)..............         1988           149            50            18               16            20
  Newcastle (7)..................         1981           146             5             3                2            16
  Red Desert (7).................         1979           111            42            14               12            23
  Reno Junction (9)..............         1991             -             -             -                -            80
Oklahoma
  Chaney Dell....................         1966         2,065           180            71               56           108
  Westana........................         1986           958            45            59               53            61
 New Mexico
  San Juan River (6).............         1955           140            60            26               21             7
 Utah
  Four Corners Gathering.........         1988           104            15             2                2             3
                                                       -----         -----         -----            -----         -----
   Total.........................                      8,319         2,127         1,374            1,208         1,647
                                                       =====         =====         =====            =====         =====
</TABLE>
<TABLE>
<CAPTION>

                                                               Average for the Quarter Ended
                                                                      March 31, 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           130           183
MGTC (12)........................         1963           252            18            13
                                                       -----         -----         -----
  Total..........................                        497           148           196
                                                       =====         =====         =====

</TABLE>

Footnotes on following page.

                                       20
<PAGE>

(1)  Our interest in all facilities is 100% except for Midkiff/Benedum (73%),
     Newcastle (50%) and Fort Union gathering system (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 March 31, 2001.
(3)  Gas throughput capacity is as of March 31, 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 acquired the remaining 28% interest in Lincoln Road in December 2000.
     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.

                                       21
<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.  Our wholly-owned 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 in 2000, on all issues for substantially less than the amount
claimed.  Western Gas and Mountain Gas filed a complaint against RIS Resources
(USA), Inc., Mountain Gas' jointventure partner in the Bird Canyon pipeline in
Wyoming, for reimbursement of 50% of the settlement amount, which was paid in
full by Mountain Gas. RIS asserted counterclaims for slander of title and
intentional interference with prospective business advantage seeking an
unspecified amount of damages, including punitive damages and other relief. On
May 8, 2001, the Company and RIS entered a confidential settlement of the
litigation pursuant to which Mountain Gas acquired all of RIS' interest in the
Bird Canyon pipeline. The parties have filed with the court a joint stipulation
of dismissal with prejudice of the litigation. Each party will bear its own fees
and costs.

Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver
County, Colorado, Civil Action No. 00-CV-1433.  We were a defendant in prior
litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation and
Western Gas Resources, Inc., United States District Court, District of Colorado,
Civil Action No. 97-WM-1332, which was settled in 2000 for an amount which did
not have a material impact on the Company's results of operations or financial
position.  We are seeking reimbursement from Amerada Hess under a contractual
indemnity.  We have amended our original complaint and requested a jury trial in
this case. Both parties filed cross motions for summary judgment. The trial
court postponed the trial date for this case scheduled for the last week of
April 2001. The trial court indicated that it will rule on the parties' cross
motions for summary judgment on liability, and will re-instate a new trial date
if necessary, after this ruling.

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

                                       22
<PAGE>

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

          None.


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


(a)  Exhibits:

     10.24  Sixth Amendment dated April 26, 2001 to Loan Agreement dated April
            29, 1999 by and among Western Gas Resources, Inc. and NationsBank,
            as agent, and the Lenders.

     10.25  Letter Amendment No. 5 dated March 30, 2001 to Second Amended and
            Restated Master Shelf Agreement dated December 19, 1991 by and
            between Western Gas Resources, Inc and The Prudential Insurance
            Company of America.

     10.26  Intercreditor Agreement dated April 26, 2001 by and among Western
            Gas Resources, Inc., Bank of America, N.A., and The Prudential
            Insurance Company of America.

(b)  Reports on Form 8-K:

     A report on Form 8-K was filed on March 30, 2001 to notify our stockholders
     of the adoption of a stockholder rights plan and the rights dividend
     distribution, which is incorporated herein by reference.

                                       23
<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: May 14, 2001                    By: /s/ LANNY F. OUTLAW
                                          -------------------
                                          Lanny F. Outlaw
                                          Chief Executive Officer and President


Date: May 14, 2001                    By: /s/WILLIAM J. KRYSIAK
                                          ---------------------
                                          William J. Krysiak
                                          Vice President - Finance
                                          (Principal Financial and Accounting
                                          Officer)

                                       24