<PAGE>

________________________________________________________________________________

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

                                    FORM 10-Q

           [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
               SECURITIES EXCHANGE ACT OF 1934

               For the quarterly period ended September 30, 2001

                                       OR

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

               For the transition period from _________ to _________

                         Commission file number 1-11392

                         THE PREMCOR REFINING GROUP INC.
             (Exact name of registrant as specified in its charter)


                    Delaware                                   43-1491230
          (State or other jurisdiction                      (I.R.S. Employer
        of incorporation or organization)                  Identification No.)

              8182 Maryland Avenue                             63105-3721
               St. Louis, Missouri                             (Zip Code)
    (Address of principal executive offices)

        Registrant's telephone number, including area code (314) 854-9696

     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 ____
                                              ---

     Number of shares of registrant's common stock, $.01 par value, outstanding
as of October 31, 2001, 100, all of which were owned by Premcor USA Inc.

________________________________________________________________________________

<PAGE>

                         The Premcor Refining Group Inc.
                                    Form 10-Q
                               September 30, 2001
                                Table of Contents
<TABLE>
<CAPTION>
                                         PART I. FINANCIAL INFORMATION

<S>                                                                                                     <C>
Item 1. Financial Statements

        Independent Accountants' Report ...............................................................   1
        Consolidated Balance Sheets as of December 31, 2000 and September 30, 2001 ....................   2
        Consolidated Statements of Operations for the Three- and Nine-Month Periods Ended
          September 30, 2000 and 2001 .................................................................   3
        Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2000 and 2001 ...   4
        Notes to Consolidated Financial Statements ....................................................   5

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations .........  16

                                         PART II. OTHER INFORMATION

Item 1. Legal Proceedings .............................................................................  34

Item 6. Exhibits and Reports on Form 8-K ..............................................................  35

        Signature .....................................................................................  37
</TABLE>


<PAGE>

FORM 10-Q - PART I
ITEM 1. FINANCIAL STATEMENTS

                         INDEPENDENT ACCOUNTANTS' REPORT
                         -------------------------------

To the Board of Directors of The Premcor Refining Group Inc.:


We have reviewed the accompanying consolidated balance sheet of The Premcor
Refining Group Inc. and subsidiaries (the "Company") as of September 30, 2001,
the related consolidated statements of operations for the three-month and
nine-month periods ended September 30, 2000 and 2001, and consolidated
statements of cash flows for the nine-month periods then ended. These financial
statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should
be made to such consolidated financial statements for them to be in conformity
with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of the
Company as of December 31, 2000, and the related consolidated statements of
operations, stockholder's equity, and cash flows for the year then ended (not
presented herein); and in our report dated February 13, 2001, we expressed an
unqualified opinion on those consolidated financial statements.

Deloitte & Touche LLP

St. Louis, Missouri
November 7, 2001



<PAGE>

                THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                    (dollars in millions, except share data)


                                              December 31,     September 30,
                                                  2000             2001
                                              ------------     -------------
                                                                (unaudited)
                        ASSETS

CURRENT ASSETS:
    Cash and cash equivalents                 $      214.8     $      279.9
    Short-term investments                             1.7              1.7
    Accounts receivable                              250.4            205.8
    Receivable from affiliates                        37.1             95.0
    Inventories                                      334.7            321.3
    Prepaid expenses and other                        34.1             30.1
                                              ------------     ------------
        Total current assets                         872.8            933.8

PROPERTY, PLANT AND EQUIPMENT, NET                   706.1            640.9
OTHER ASSETS                                         117.2            119.6
NOTE RECEIVABLE FROM AFFILIATE                         4.9              4.9
                                              ------------     ------------
                                              $    1,701.0     $    1,699.2
                                              ============     ============

         LIABILITIES AND STOCKHOLDER'S EQUITY

CURRENT LIABILITIES:
    Accounts payable                          $      418.4     $      275.4
    Payable to affiliates                             90.8            156.9
    Accrued expenses and other                        64.8             63.9
    Accrued taxes other than income                   37.1             22.4
                                              ------------     ------------
        Total current liabilities                    611.1            518.6

LONG-TERM DEBT                                       796.9            774.7
DEFERRED INCOME TAXES                                   --             30.3
OTHER LONG-TERM LIABILITIES                           65.5            105.6
COMMITMENTS AND CONTINGENCIES                           --               --

COMMON STOCKHOLDER'S EQUITY:
    Common stock ($0.01 par value per share;
      1,000 shares authorized and 100 shares
      issued and outstanding)                           --               --
    Paid-in capital                                  159.2            133.4
    Retained earnings                                 68.3            136.6
                                              ------------     ------------
        Total common stockholder's equity            227.5            270.0
                                              ------------     ------------
                                              $    1,701.0     $    1,699.2
                                              ============     ============



   The accompanying notes are an integral part of these financial statements.


                                       2

<PAGE>

                THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                        (unaudited, dollars in millions)
<TABLE>
<CAPTION>
                                            For the Three Months  For the Nine Months
                                             Ended September 30,  Ended September 30,
                                            --------------------  -------------------
                                              2000        2001      2000       2001
                                            --------    --------  --------   --------
<S>                                         <C>         <C>       <C>        <C>
NET SALES AND OPERATING REVENUES            $2,032.6    $1,701.2  $5,312.4   $5,265.0

EXPENSES:
   Cost of sales                             1,862.8     1,489.3   4,762.7    4,574.6
   Operating expenses                          115.0        85.5     327.9      265.7
   General and administrative expenses          12.3        14.9      34.9       42.0
   Depreciation                                  9.7         8.4      26.6       24.4
   Amortization                                  9.2         9.5      25.6       28.1
   Refinery restructuring and other charges       --        26.2        --      190.2
                                            --------    --------  --------   --------
                                             2,009.0     1,633.8   5,177.7    5,125.0
                                            --------    --------  --------   --------

OPERATING INCOME                                23.6        67.4     134.7      140.0

   Interest and finance expense                (18.9)      (18.1)    (56.2)     (56.7)
   Interest income                               3.1         3.2       9.9        9.4
                                            --------    --------  --------   --------

INCOME BEFORE INCOME TAXES
   AND EXTRAORDINARY ITEM                        7.8        52.5      88.4       92.7

   Income tax provision                         (0.2)      (21.7)     (0.6)     (24.9)
                                            --------    --------  --------   --------

NET INCOME BEFORE
  EXTRAORDINARY ITEM                             7.6        30.8      87.8       67.8

   Gain on repurchase of long-term debt
     (net of income taxes of $0.3 million)        --         0.5        --        0.5
                                            --------    --------  --------   --------

NET INCOME                                  $    7.6    $   31.3  $   87.8   $   68.3
                                            ========    ========  ========   ========
</TABLE>

   The accompanying notes are an integral part of these financial statements.




                                       3

<PAGE>

                THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                        (unaudited, dollars in millions)

<TABLE>
<CAPTION>
                                                                                                For the Nine Months
                                                                                                Ended September 30,
                                                                                             -------------------------
                                                                                               2000             2001
                                                                                             --------         --------
<S>                                                                                          <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net income                                                                               $   87.8         $   68.3
    Extraordinary gain                                                                              -             (0.5)

    Adjustments
      Depreciation                                                                               26.6             24.4
      Amortization                                                                               31.6             34.4
      Deferred taxes                                                                                -             37.2
      Refinery restructuring and other charges                                                      -            139.3
      Other, net                                                                                  0.4             (2.5)

    Cash provided by (reinvested in) working capital -
      Accounts receivable, prepaid expenses and other                                           (84.4)            48.6
      Inventories                                                                              (149.5)            13.4
      Accounts payable, accrued expenses and taxes other
        than income                                                                             194.5           (158.6)
      Affiliate accounts receivable and payable                                                   2.7              8.2
                                                                                             --------         --------
           Net cash provided by operating activities                                            109.7            212.2
                                                                                             --------         --------
CASH FLOWS FROM INVESTING ACTIVITIES:
    Expenditures for property, plant and equipment                                             (110.3)           (49.1)
    Expenditures for turnaround                                                                 (23.8)           (41.3)
    Proceeds from disposals of property, plant and equipment                                      0.5              0.1
    Purchases of short-term investments                                                          (1.5)            (1.7)
    Sales and maturities of short-term investments                                                1.5              1.7
                                                                                             --------         --------
           Net cash used in investing activities                                               (133.6)           (90.3)
                                                                                             --------         --------
CASH FLOWS FROM FINANCING ACTIVITIES:
    Repurchase of long-term debt                                                                    -            (20.3)
    Capital lease payments                                                                       (7.0)            (1.1)
    Capital contribution returned                                                               (26.0)           (25.8)
    Deferred financing costs                                                                     (1.9)            (9.6)
                                                                                             --------         --------
           Net cash used in financing activities                                                (34.9)           (56.8)
                                                                                             --------         --------
NET INCREASE (DECREASE) IN CASH AND
    CASH EQUIVALENTS                                                                            (58.8)            65.1
CASH AND CASH EQUIVALENTS, beginning of period                                                  284.9            214.8
                                                                                             --------         --------
CASH AND CASH EQUIVALENTS, end of period                                                     $  226.1         $  279.9
                                                                                             ========         ========
</TABLE>


   The accompanying notes are an integral part of these financial statements.

                                        4

<PAGE>

FORM 10-Q - PART I
ITEM 1. FINANCIAL STATEMENTS (continued)

The Premcor Refining Group Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2001
(tabular dollar amounts in millions of U.S. dollars)

1.   Basis of Preparation

     The Premcor Refining Group Inc. is a privately held company with two
principal direct, wholly-owned subsidiaries, Premcor P.A. Pipeline Company and
Premcor Investments Inc. The Company is 100% owned by Premcor USA Inc., which in
turn is 100% owned by Premcor Inc.

     The accompanying unaudited consolidated financial statements of The Premcor
Refining Group Inc. and subsidiaries (the "Company") are presented pursuant to
the rules and regulations of the Securities and Exchange Commission in
accordance with the disclosure requirements for Form 10-Q. In the opinion of the
management of the Company, the unaudited consolidated financial statements
reflected all adjustments (consisting only of normal recurring adjustments)
necessary to fairly state the results for the interim periods presented.
Operating results for the three- and nine-month periods ended September 30, 2001
were not necessarily indicative of the results that may be expected for the year
ended December 31, 2001. These unaudited financial statements should be read in
conjunction with the audited financial statements and notes included in the
Company's 2000 Annual Report on Form 10-K.

2.   New and Proposed Accounting Standards

     In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 1999, the FASB issued
SFAS No. 137 "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB Statement No. 133" which
delayed the effective date of SFAS No. 133 for one year to fiscal years
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138
"Accounting for Certain Derivative Instruments and Hedging Activities" which
amended various provisions of SFAS No.




<PAGE>

133. The Company adopted SFAS No. 133, as amended, effective January 1, 2001.
The adoption of SFAS No. 133 did not have a material impact on the Company's
financial position or results of operations because the Company has historically
marked to market all financial instruments used in the implementation of the
Company's hedging strategies.

     On July 20, 2001, the FASB issued SFAS No. 141 "Business Combinations" and
SFAS No. 142 "Goodwill and Other Intangible Assets." SFAS No. 141, which became
effective on issuance, requires business combinations initiated after June 30,
2001 be accounted for using the purchase method of accounting and addresses the
initial recording of intangible assets separate from goodwill. SFAS No. 142
requires that goodwill and intangible assets with indefinite lives will not be
amortized, but will be tested at least annually for impairment. Intangible
assets with finite lives will continue to be amortized. SFAS No. 142 is
effective for fiscal years beginning after December 15, 2001. The Company does
not expect the implementation of these standards to have a material effect on
its financial position and results of operations.

     In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset
Retirement Obligations". SFAS No. 143 addresses when a liability should be
recorded for asset retirement obligations and how to measure this liability. The
initial recording of a liability for an asset retirement obligation will require
the recording of a corresponding asset, which will be required to be amortized.
SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The
Company is in the process of evaluating the impact of the adoption of this
standard on its financial position and results of operations.

     The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants ("AICPA") has issued an exposure draft of a
proposed statement of position ("SOP") entitled "Accounting for Certain Costs
and Activities Related to Property, Plant and Equipment." If adopted as
proposed, this SOP would require companies to expense as incurred turnaround
costs, defined as "the non-capital portion of major maintenance costs." Adoption
of the proposed SOP would also require that any existing unamortized turnaround
costs be expensed immediately. A turnaround is a periodically required standard
procedure for maintenance of a refinery that involves the shutdown and
inspection of major processing units and generally occurs every three to five
years. Turnaround costs include actual direct and contract labor and material
costs for the overhaul, inspection, and replacement of major components of
refinery processing and support units performed during turnaround. Turnaround
costs, which are included in the Company's consolidated balance sheet in "Other
Assets," are currently amortized by the Company on a straight-line basis over
the period until the next scheduled turnaround, beginning the month following
completion. The amortization of turnaround costs is presented as "Amortization"
in the Company's consolidated statements of operations.

     The proposed SOP requires adoption for fiscal years beginning after June
15, 2002. If this proposed change were in effect at September 30, 2001, the
Company would have been required to write-off unamortized turnaround costs of
approximately $101 million. Unamortized turnaround costs will change throughout
the year as maintenance turnarounds are performed and past maintenance
turnarounds are amortized. If adopted in its present form, charges related to
this proposed change would be taken in the first quarter of 2003 and would be
reported as a cumulative effect of an accounting change, net of tax, in the
consolidated statements of operations.

3.   Inventories




<PAGE>

     The carrying value of inventories consisted of the following:

<TABLE>
<CAPTION>
                                                               December 31,     September 30,
                                                                   2000             2001
                                                              ------------      -------------
           <S>                                                <C>               <C>
           Crude oil ....................................     $     125.3       $    80.0
           Refined products and blendstocks .............           185.7           219.2
           Warehouse stock and other ....................            23.7            22.1
                                                              ------------      -------------
                                                              $     334.7       $   321.3
                                                              ============      =============
</TABLE>


     The market value of crude oil, refined products and blendstocks inventories
at September 30, 2001 was approximately $50.4 million (December 31, 2000 -
$100.8 million) above carrying value.

4.   Other Assets

     Other assets consisted of the following:

<TABLE>
<CAPTION>
                                                               December 31,     September 30,
                                                                   2000             2001
                                                             --------------   ----------------
           <S>                                               <C>              <C>
           Deferred turnaround costs ....................     $      94.1     $        100.6
           Deferred financing costs .....................            14.5               17.8
           Deferred tax asset ...........................             7.2               --
           Other ........................................             1.4                1.2
                                                              -------------   ----------------
                                                              $     117.2     $        119.6
                                                              =============   ================
</TABLE>



     Amortization of deferred financing costs for the three- and nine-month
periods ended September 30, 2001 was $2.0 million (2000 - $2.0 million) and $6.1
million (2000 - $5.9 million), respectively, and was included in "Interest and
finance expense". During 2001, the Company incurred approximately $9.6 million
of deferred financing costs to amend and restate its secured revolving credit
facility and wrote-off $0.2 million of its deferred financing costs related to
the Company's senior notes repurchased in September 2001.

5.   Related Party Transactions

     Port Arthur Coker Company L.P.

     The Company and Port Arthur Coker Company L.P. (the "Port Arthur Coker
Company") have entered into certain agreements associated with the operations
between the coking, hydrocracking, and sulfur removal facilities of the Port
Arthur Coker Company and the Company's Port Arthur refinery. Premcor USA Inc. is
100% owned and Port Arthur Coker Company's general partner, Sabine River Holding
Corp., is 90% owned by Premcor Inc. Balances and activity related to a services
and supply, product purchase, and ancillary lease agreement were as follows:

     As of September 30, 2001, the Company had an outstanding receivable from
Port Arthur Coker Company of $36.3 million (December 31, 2000 - $28.0 million)
and a payable to Port Arthur Coker Company of $85.7 million (December 31, 2000 -
$50.4 million) related to ongoing operations. As of September 30, 2001, the
Company had a note receivable from Port Arthur Coker Company of $7.5 million
(December 31, 2000 - $7.0 million) related to construction




<PAGE>


management services of which $4.9 million (December 31, 2000 - $4.9 million) was
accounted for as a long-term asset and the remainder as a current asset.


     The Company generated $30.3 million and $100.9 million in revenues for the
three- and nine-month periods ended September 30, 2001, respectively, related to
lease and pipeline tariff fees and to the sale of feedstocks and hydrogen to
Port Arthur Coker Company. The Company incurred $464.6 million and $1,496.5
million in costs of sales for purchases of finished and intermediate refined
products and crude oil from Port Arthur Coker Company for the three- and nine-
month periods ended September 30, 2001, respectively. The Company recorded
reimbursements of operating expenses of $2.4 million and $19.2 million for
services provided to Port Arthur Coker Company for the three- and nine-month
periods ended September 30, 2001. There were no revenues or expenses generated
from these agreements in the first nine months of 2000.

6.   Working Capital Facilities

     In August 2001, the Company amended and restated its secured revolving
credit facility for a period of two years through August 2003. This new
agreement provides for borrowings and the issuance of letters of credit of up to
the lesser of $650 million or the amount available under a defined borrowing
base calculation. The borrowing base calculation takes into consideration the
Company's cash and eligible cash equivalents, eligible investments, eligible
receivables, eligible petroleum inventories and paid but unexpired letters of
credit. The Company is required to comply with certain financial covenants
including maintaining defined levels of working capital, cash, cash equivalents
and qualified investments, tangible net worth, and cumulative cash flow. Direct
cash borrowings under the credit facility are limited to $50 million.

7.   Repurchase of Long-Term Debt

     In September 2001, the Company repurchased in the open market, $21.3
million in face value of its 9 1/2% Senior Notes due September 15, 2004 for
$20.3 million. As a result of this transaction, the Company recorded an
extraordinary pre-tax gain of $0.8 million (net of taxes - $0.5 million) which
included the write-off of deferred financing costs related to the debt.

8.   Interest and Finance Expense

     Interest and finance expense included in the statements of operations
consisted of the following:




<PAGE>

<TABLE>
<CAPTION>
                                                For the Three Months            For the Nine Months
                                                 Ended September 30,            Ended September 30,
                                                  2000         2001              2000         2001
                                                --------     ---------         --------     ---------
         <S>                                    <C>          <C>               <C>          <C>
         Interest expense .................     $   18.6     $    17.2         $   55.3     $    53.3
         Financing costs ..................          2.1           2.0              6.1           6.3
         Capitalized interest .............         (1.8)         (1.1)            (5.2)         (2.9)
                                                --------     ---------         --------     ---------
                                                $   18.9     $    18.1         $   56.2     $    56.7
                                                ========     =========         ========     =========
</TABLE>

     Cash paid for interest for the three- and nine-month periods ended
September 30, 2001 was $17.9 million (2000 - $19.1 million) and $54.9 million
(2000 - $55.6 million), respectively.

9.   Refinery Restructuring and Other Charges

     Refinery restructuring and other charges consisted of $167.2 million
related to the January, 2001 closure of the Company's Blue Island, Illinois
refinery, a $14.0 million charge related to the environmental liability for
previously-owned retail properties and a $9.0 million charge related to the
write-off of certain assets at the Company's Port Arthur refinery that are no
longer in service.

Blue Island Closure

     In January 2001, the Company ceased operations at its Blue Island refinery
due to economic factors and a decision that the capital expenditures necessary
to produce low sulfur transportation fuels required by recently adopted
Environmental Protection Agency regulations could not produce an acceptable
return on investment. The Company continues to utilize its petroleum products
storage facility at the refinery site to supply products to the Chicago and
other Midwest markets from the Company's operating refineries. Since the Blue
Island refinery operation has been only marginally profitable in recent years
and since we will continue to operate a petroleum products storage and
distribution business from the Blue Island site, the closure of the refinery is
not expected to have a significant negative impact on net income or cash from
operations. The only significant effect on net income and cash flow will result
from the actual shutdown process and subsequent environmental site remediation
as discussed below.

     Management adopted an exit plan that detailed the shutdown of the process
units at the refinery and the subsequent environmental remediation of the site.
The shutdown of the process units was completed during the first quarter of
2001. The Company is currently in discussions with federal, state, and local
governmental agencies concerning an investigation of the site and a remediation
program that would allow for redevelopment of the site for other manufacturing
uses at the earliest possible time. Until the site remediation plan is
finalized, it is not possible to estimate the completion date for the
remediation, but the Company anticipates that the remediation activities will
continue for an extended period of time.

     A pre-tax charge of $150.0 million was recorded in the first quarter of
2001 and an additional charge of $17.2 million was recorded in the third quarter
of 2001. The original charge included $92.5 million of non-cash asset write-offs
in excess of realizable value and a reserve for future costs of $57.5 million,
consisting of $12.0 million for severance costs, $26.4 million for the ceasing
of operations, preparation of the plant for permanent closure and equipment
remediation and $19.1 million for site remediation and other environmental
matters. The third quarter charge of $17.2 million included an adjustment of
$5.6 million to the asset write-off to reflect changes in realizable asset value
and an increase of $11.6 million related to a continued evaluation of expected
future expenditures as detailed below. The Company expects to spend
approximately $40 million in 2001 related to the $69.1 million adjusted reserve
for future costs, with the majority of the remainder to be spent over the next
several years. The following schedule summarizes the restructuring reserve
balance and net cash activity as of September 30, 2001:




<PAGE>

<TABLE>
<CAPTION>
                                                                                              Reserve at
                                                 Initial        Reserve        Net Cash       September
                                                 Reserve      Adjustment        Outlay         30, 2001
                                               -----------    ----------   ---------------   -----------
   <S>                                         <C>            <C>          <C>               <C>
   Employee severance ......................    $  12.0       $   0.7        $    10.5       $       2.2
   Plant closure/equipment remediation .....       26.4           6.3             16.1              16.6
   Site remediation/environmental matters ..       19.1           4.6              1.7              22.0
                                               -----------    -----------  ---------------   -----------
                                               $   57.5       $  11.6        $    28.3       $      40.8
                                               ===========    ===========  ===============   ===========
</TABLE>

     The site remediation and environmental reserve takes into account costs
that the Company can reasonably estimate at this time. As the site remediation
plan is finalized and work performed, further adjustments of the estimate may be
necessary. The Company anticipates that remediation activities will continue for
an extended period of time. The Company is also evaluating other potential
environmental risk management options in order to quantify more precisely the
cost of remediation of the site and to provide the governmental agencies
financial assurance that, once begun, remediation of the site will be completed
in a timely and prudent manner.

     The Blue Island refinery employed 297 employees, both hourly (covered by
collective bargaining agreements) and salaried, approximately 280 of whom were
terminated during the first nine months of 2001. The remaining employees are all
salaried employees and the majority of them will terminate employment within the
year as the shutdown progresses.

Environmental Liability for Retail Sites

     The retail environmental charge of $14 million represents a change in
estimate relative to the Company's clean up obligation regarding the previously
discontinued retail division. More complete information concerning site by site
clean up plans and changing postures of state regulatory agencies prompted the
change in estimate.

Port Arthur Refinery Assets

     In September 2001, the Company incurred a charge of $5.8 million related to
the net asset value of the idled coker units at the Port Arthur refinery. The
Company now believes that an alternative use of the coker units is not probable
at this time. The Company also accrued $3.2 million for future environmental
clean-up costs related to the site.

10.  Income Taxes

     The Company made net cash income tax payments during the three-month and
nine-month periods ended September 30, 2001 of $0.3 million (2000 -$2.5 million)
and $3.1 million (2000 - $3.3 million), respectively. The income tax provision
for the three-month and nine-month periods ended September 30, 2001 was $21.7
million and $24.9 million, respectively. The income tax provision of $24.9
million for the nine-month period ended September 30, 2001 included the effect
of the Company's reversal during the first quarter of 2001 of its remaining
deferred tax valuation allowance of $12.4 million. This reversal resulted from
the Company's analysis of the




<PAGE>

likelihood of realizing the future tax benefit of its federal and state tax loss
carryforwards, alternative minimum tax credits and federal and state business
tax credits. The income tax provision for the three-month and nine-month periods
ended September 30, 2000 was $0.2 million and $0.6 million, respectively, which
represented current state taxes.


11.  Commitments and Contingencies

     As a result of its activities, the Company is the subject of a number of
legal and administrative proceedings, including proceedings related to
environmental matters. All such matters that could be material or to which a
governmental authority is a party and which involve potential monetary sanctions
of $100,000 or greater are described below.

     Port Arthur: Enforcement. The Texas Natural Resource Conservation
Commission ("TNRCC") conducted a site inspection of the Port Arthur refinery in
the spring of 1998. In August 1998, the Company received a notice of enforcement
alleging 47 air-related violations and 13 hazardous waste-related violations.
The number of allegations was significantly reduced in an enforcement
determination response from TNRCC in April 1999. A follow-up inspection of the
refinery in June 1999 concluded that only two items remained outstanding, namely
that the refinery failed to maintain the temperature required by the air permit
at one of its incinerators and that five process wastewater sump vents did not
meet applicable air emission control requirements. The TNRCC also conducted a
complete refinery inspection in the second quarter of 1999, resulting in another
notice of enforcement in August 1999. This notice alleged nine air-related
violations, relating primarily to deficiencies in the Company's upset reports
and emissions monitoring program, and one hazardous waste-related violation
concerning spills. The 1998 and 1999 notices were combined and referred to the
TNRCC's litigation division. On September 7, 2000 the TNRCC issued a notice of
enforcement regarding the Company's alleged failure to maintain emission rates
at permitted levels. In May 2001, the TNRCC proposed an order covering some of
the 1998 hazardous waste allegations, the incinerator temperature deficiency,
the process wastewater sumps, and all of the 1999 and 2000 allegations, and
proposing the payment of a fine of $562,675 and the implementation of a series
of technical provisions requiring corrective actions. Negotiations with the
TNRCC are ongoing and are not expected to be resolved in 2001.

     Lima: Finding of Violation. On July 10, 2001, the Ohio Environmental
Protection Agency issued a finding of violation by the Company of state and
federal laws regarding releases of annual benzene quantities into refinery
wastewater streams in excess of that allowed and downtime of continuous emission
control monitors that exceeded the allowed 5%. The Company has settled this
action, paid a fine of $120,000 and implemented preventive programs to ensure
future compliance.

     Hartford: Federal Enforcement. In February 1999, the federal government
filed a complaint in the matter United States v. Clark Refining & Marketing,
Inc., alleging violations of the Clean Air Act and regulations promulgated
thereunder, in the operation and permitting of the Hartford refinery fluidized
catalytic cracking unit. The Company settled this action in July 2001 by
agreeing to install a wet gas scrubber on the fluid catalytic cracking unit at
an estimated cost of $8 million to $10 million, and low nitrogen oxide burners
at a cost of $1.5 million, and agreeing to pay a civil penalty of $2 million.

     Blue Island: Federal and State Enforcement. In September 1998, the federal
government




<PAGE>


filed a complaint, United States v. Clark Refining & Marketing, Inc., alleging
that the Company had operated the Blue Island refinery in violation of certain
federal laws relating to air pollution, water pollution and waste management.
The Illinois Attorney General intervened in this matter and the State of
Illinois also brought an action alleging violations under state environmental
laws. The state enforcement action is People ex rel. Ryan v. Clark Refining &
Marketing Inc. and is currently pending in the Circuit Court of Cook County,
Illinois. The Company is seeking to settle both cases simultaneously. In 2000,
prior to deciding to close the Blue Island refinery, an agreement in principle
was reached to settle both matters, including by paying a civil penalty of $2.25
million, installing a wet gas scrubber on the fluidized catalytic cracking unit,
and making changes and enhancements to certain operating practices and
procedures at the refinery at an estimated cost of $6 million. Subsequently, the
Company decided to close the Blue Island refinery. Since the proposed
settlements were based on the assumption that the refinery would continue in
operation, the Company is renegotiating the settlement of this matter in a
manner appropriate to its closure, which has become linked to discussions
regarding the remediation process at that refinery. There can be no assurance
that a settlement can be reached and a consent decree successfully negotiated
regarding the two enforcement actions.

     Blue Island: Criminal Matters. In June 2000, the Refining Group pled guilty
to one felony count of violating the Clean Water Act and one count of conspiracy
to defraud the United States at the Blue Island refinery. These charges arose
out of the discovery, during a multimedia investigation at the site conducted in
1996, that two former employees had allegedly falsified certain reports
regarding wastewater sent to the municipal wastewater treatment facility. As
part of the plea agreement, the Company agreed to pay a fine of $2 million and
was placed on probation for three years. The Company does not anticipate this to
have a significant adverse impact on its business on an ongoing basis. The
primary remaining condition of probation is an obligation not to commit future
environmental crimes. If the Company were to commit a crime in the future, it
would be subject not only to prosecution for that new violation, but also to a
separate charge that it had violated a condition of its probation. Any violation
of probation charge would be brought before the same judge who entered the
original sentence, and that judge would have the authority to enter a new and
potentially more severe sentence for the offense to which the Company pled
guilty in June, 2000. The two former employees are currently under criminal
indictment.

     Sashabaw Road Retail Location: State Enforcement. In July 1994, the
Michigan Department of Natural Resources brought an action alleging that one of
the Company's retail locations caused groundwater contamination, necessitating
the installation of a new $600,000 drinking water system. The Michigan
Department of Natural Resources sought reimbursement of this cost. Although this
site may have contributed to contamination in the area, the Company maintained
that numerous other sources were responsible and that a total reimbursement
demand from the Company would be excessive. Mediation resulted in a $200,000
finding against the Company. The Company made an offer of judgment equal to the
mediation finding. The offer was rejected by the Michigan Department of Natural
Resources and the matter was tried in November 1999, resulting in a judgment
against the Company of $110,000 plus interest. Since the judgment was over 20%
below the previous settlement offer, under applicable state law the Company is
entitled to recover its legal fees. Both the Michigan Department of Natural
Resources and the Company have appealed the decision.

     Port Arthur: Natural Resource Damage Assessment. In 1999, Premcor USA Inc.
and Chevron received a notice from a number of federal and Texas agencies that a
study would be conducted to determine whether any natural resource damage
occurred as a result of the




<PAGE>

operation of the Port Arthur refinery prior to January 1, 2000. The Company is
cooperating with the government agencies in this investigation. The Company
entered into an agreement with Chevron pursuant to which Chevron will indemnify
the Company for the claim in consideration of a payment of $750,000.

     Port Arthur and Lima Refineries. The original refineries on the sites of
the Port Arthur and Lima refineries began operating in the late 1800s and early
1900s, prior to modern environmental laws and methods of operation. There is
contamination at these sites, which the Company believes will be required to be
remediated. Under the terms of the Company's 1995 purchase of the Port Arthur
refinery, Chevron U.S.A., the former owner, retained liability for all required
investigation and remediation relating to pre-purchase contamination discovered
by June 1997, except with respect to certain areas on or around which active
processing units are located, which are the Company's responsibility. Extensive
due diligence efforts prior to the acquisition and additional investigation
after the acquisition documented contamination for which Chevron is responsible.
In June 1997, the Company entered into an agreed order with Chevron and the
TNRCC, that incorporates this contractual division of remediation
responsibilities into an agreed order. The Company has accrued $11.5 million for
the Port Arthur remediation at September 30, 2001. Under the terms of the
purchase of the Lima refinery, BP PLC ("BP"), the former owner, indemnified the
Company for all pre-existing environmental liabilities, except for contamination
resulting from releases of hazardous substances in or on sewers, process units
and other equipment at the refinery as of the closing date, but only to the
extent the presence of these hazardous substances was as a result of normal
operations of the refinery and does not constitute a violation of any
environmental law. Although the Company is not primarily responsible for the
majority of the currently required remediation of these sites, the Company may
become jointly and severally liable for the cost of investigating and
remediating a portion of these sites in the event that Chevron or BP fails to
perform the remediation. In such event, however, we believe we would have a
contractual right of recovery from these entities. The cost of any such
remediation could be substantial and could have a material adverse effect on the
Company's financial position.

     Blue Island Refinery Decommissioning and Closure. In January 2001, the
Company ceased operations at the Blue Island, Illinois refinery. The
decommissioning, dismantling and tear down of the facility is underway. The
Company is currently in discussions with federal, state and local governmental
agencies concerning remediation of the site. The governmental agencies have
proposed a remediation process patterned after national contingency plan
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"). The Company has proposed to the agencies a site
investigation and remediation that incorporates certain elements of the CERCLA
process and the State of Illinois' site remediation program. The Company is also
evaluating other potential environmental risk management options in order to
allow it to quantify more precisely the cost of remediation of the site and to
provide the governmental agencies financial assurance that, once begun,
remediation of the site will be completed in a timely and prudent manner.

     Former Retail Sites. In 1999, the Company sold its former retail marketing
business, which the Company operated from time to time on a total of 1,150
sites. During the normal course of operations of these sites, releases of
petroleum products from underground storage tanks have occurred. Federal and
state laws require that contamination caused by such releases at these sites be
assessed and remediated to meet applicable standards. The enforcement of the
underground storage tank regulations under the Resource Conservation and
Recovery Act has been delegated to the states that administer their own
underground storage tank programs. The Company's


                                       13

<PAGE>

obligation to remediate such contamination varies, depending upon the extent of
the releases and the stringency of the laws and regulations of the states in
which the releases were made. A portion of these remediation costs may be
recoverable from the appropriate state underground storage tank reimbursement
fund once the applicable deductible has been satisfied. The 1999 sale included
672 sites, 225 of which had no known preclosure contamination, 365 of which had
known pre-closure contamination of varying extent, and 80 of which had been
previously remediated. The purchaser of the retail division assumed pre-closure
environmental liabilities of up to $50,000 per site at the sites on which there
was no known contamination. The Company is responsible for any liability above
that amount per site for pre-closure liabilities, subject to certain time
limitations. With respect to the sites on which there was known pre-closing
contamination, the Company retained liability for 50% of the first $5 million in
remediation costs and 100% of remediation costs over that amount. The Company
retained any remaining pre-closing liability for sites that had been previously
remediated.

     Of the remaining 478 former retail sites not sold in the 1999 transaction
described above, the Company has sold all but 13 in open market sales and
auction sales. The Company generally retains the remediation obligations for
sites sold in option market sales with identified contamination. Of the retail
sites sold in auctions, the Company agreed to retain liability for all of these
sites until an appropriate state regulatory agency issues a letter indicating
that no further remedial action is necessary. However, these letters are subject
to revocation if it is later determined that contamination exists at the
properties and the Company would remain liable for the remediation of any
property at which such a letter was received but subsequently revoked. The
Company is currently involved in the active remediation of 139 of the retail
sites sold in open market and auction sales and is actively seeking to sell the
remaining 13 properties. As of September 30, 2001, the Company had expended $14
million to satisfy the obligations described above and had $14.3 million accrued
to satisfy those obligations in the future.

     Former Terminals. In December 1999, the Company sold 15 refined product
terminals to a third party, but retained liability for environmental matters at
four terminals and, with respect to the remaining eleven terminals, the first
$250,000 per year of environmental liabilities for a period of six years up to a
maximum of $1.5 million. As of September 30, 2001, the Company had expended $0.5
million on these obligations and has accrued $2.9 million for these obligations
in the future.

     Legal and Environmental Reserves. As a result of its normal course of
business, the Company is a party to a number of legal and environmental
proceedings. As of September 30, 2001, the Company had accrued a total of $71
million, on an undiscounted basis, for legal and environmental-related
obligations that may result from the matters noted above and other legal and
environmental matters. The Company is of the opinion that the ultimate
resolution of these claims, to the extent not previously provided for, will not
have a material adverse effect on the consolidated financial condition, results
of operations or liquidity of the Company. However, an adverse outcome of any
one or more of these matters could have a material effect on quarterly or annual
operating results or cash flows when resolved in a future period.

     Tier 2 Motor Vehicle Emission Standards. In February 2000, the
Environmental Protection Agency ("EPA") promulgated the Tier 2 Motor Vehicle
Emission Standards Final Rule for all passenger vehicles, establishing standards
for sulfur content in gasoline. These regulations mandate that the sulfur
content of gasoline at any refinery not exceed 30 ppm during any calendar year
by January 1, 2006. These requirements will be phased in beginning on January 1,
2004. Modifications will be required at each of the Company's refineries as a
result of the Tier 2



                                       14

<PAGE>

standards. Based on preliminary estimates, the Company believes that compliance
with the new Tier 2 gasoline specifications will require capital expenditures in
the aggregate through 2005 in a range of $180 million to $225 million for its
refineries. More than 90% of the projected investment is expected to be incurred
during 2002 through 2004 with the greatest concentration of spending occurring
in 2003.

     Low Sulfur Diesel Standards. In addition, in January 2001, the EPA
promulgated its on-road diesel regulations, which will require a 97% reduction
in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with
full compliance by January 1, 2010. Refining industry groups have filed two
lawsuits, which may delay implementation of the on-road diesel rule beyond 2006.
In its release, the EPA estimated that the overall cost to fuel producers of the
reduction in sulfur content would be approximately $0.04 per gallon. The EPA has
also announced its intention to review the sulfur content in diesel fuel sold to
off-road consumers. If regulations are promulgated to regulate the sulfur
content of off-road diesel, the Company expects the sulfur requirement to be
either 500 ppm, which is the current on-road limit, or 15 ppm, which will be the
future on-road limit. If the new off-road standard is 500 ppm, the capital
expenditures necessary for the Company to comply with the diesel standards may
be significantly reduced because the Port Arthur refinery currently meets the
500 ppm specification. The Company would thus continue to have a market for its
current diesel production at Port Arthur, albeit a smaller and lower priced
market, and therefore could elect not to make any capital expenditures necessary
to comply with the new on-road standard. Depending upon the standard promulgated
for off-road diesel, if any, and the compliance strategy the Company adopts, the
Company estimates that its capital expenditure cost in the aggregate through
2006 of complying with the diesel standards utilizing existing technologies may
range from $150 million to $200 million. More than 90% of the projected
investment is expected to be incurred during 2004 through 2006 with the greatest
concentration of spending occurring in 2005.

     Maximum Available Control Technology. In September 1998, the EPA proposed
regulations to implement Phase II of the petroleum refinery Maximum Achievable
Control Technology rule under the federal Clean Air Act, referred to as MACT II,
which regulates emissions of hazardous air pollutants from certain refinery
units. Finalization of the MACT II regulations has been delayed in an attempt to
harmonize the MACT II requirements with Tier 2 gasoline and low-sulfur diesel
requirements. If the MACT II regulations are finalized and implemented as
proposed, the Company expects to spend approximately $60 million in the three
years following their finalization in order to comply. We expect the spending to
be approximately evenly divided in each of the three years.

     Crude Oil Purchase Commitment. In 1999, the Company sold crude oil linefill
in the pipeline system supplying the Lima refinery. An agreement is in place
that requires the Company to repurchase approximately 2.4 million barrels of
crude oil in this pipeline system in September 2002 at the then current market
prices, unless extended by mutual consent. The Company has hedged the price risk
related to the repurchase obligations through the purchase of exchange-traded
futures contracts.



                                       15

<PAGE>

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

Forward-Looking Statements

     Certain statements in this document are forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. These statements are subject to the safe harbor
provisions of this legislation. Words such as "expects," "intends," "plans,"
"projects," "believes," "estimates," "will" and similar expressions typically
identify such forward-looking statements.

     Even though we believe our expectations regarding future events are based
on reasonable assumptions, forward-looking statements are not guarantees of
future performance. Important factors that could cause actual results to differ
materially from those contained in our forward-looking statements include, among
others, changes in:

     . Industry-wide refining margins;
     . Crude oil and other raw material costs, embargoes, industry expenditures
       for the discovery and production of crude oil, and military conflicts
       between, or internal instability in, one or more oil-producing countries,
       and governmental actions;
     . Market volatility due to world and regional events;
     . Availability and cost of debt and equity financing;
     . Labor relations;
     . U.S. and world economic conditions;
     . Supply and demand for refined petroleum products;
     . Reliability and efficiency of our operating facilities which are effected
       by such potential hazards as equipment malfunctions, plant
       construction/repair delays, explosions, fires, oil spills and the impact
       of severe weather;
     . Actions taken by competitors which may include both pricing and expansion
       or retirement of refinery capacity;
     . Civil, criminal, regulatory or administrative actions, claims or
       proceedings and regulations dealing with protection of the environment,
       including refined petroleum product composition and characteristics;
     . Other unpredictable or unknown factors not discussed.

     Because of all of these uncertainties, and others, you should not place
undue reliance on our forward-looking statements.



                                       16

<PAGE>

Overview

        We are one of the largest independent petroleum refiners and suppliers
of unbranded transportation fuels, heating oil, petrochemical feedstocks,
petroleum coke and other petroleum products in the United States. We own and
operate three refineries with a combined crude oil throughput capacity of
approximately 490,000 barrels per day, or bpd. Our refineries are located in
Port Arthur, Texas; Lima, Ohio; and Hartford, Illinois. The strategic location
of our assets allows us to sell petroleum products in the Midwest, where demand
for light products, such as transportation fuels, petrochemical feedstocks and
heating oil, has historically exceeded refining production, as well as in the
Gulf Coast and eastern and southeastern United States. We sell our products on
an unbranded basis to approximately 600 distributors and chain retailers through
our own product distribution system and an extensive third-party owned product
distribution system, as well as in the spot market.

        Our Port Arthur, Texas refinery has a crude oil throughput capacity of
approximately 250,000 bpd. We lease 100% of this crude oil throughput capacity
to our affiliate, Port Arthur Coker Company, but currently utilize approximately
50,000 bpd of the crude oil throughput capacity through a processing
arrangement. At our Port Arthur refinery site, the Port Arthur Coker Company
owns and operates a delayed coking unit, hydrocracker unit and sulfur complex
which are designed to process sour and heavy sour crude oils. We have agreements
with Port Arthur Coker Company whereby we lease certain of our refinery
equipment to them, provide to them certain operating, maintenance and other
services, and purchase from them all of the output of the Port Arthur Coker
Company units. We also lease back a portion of our leased equipment and utilize
a portion of the equipment of Port Arthur Coker Company through a processing
arrangement. As a result of these agreements, Port Arthur Coker Company is a
significant supplier of partially-refined intermediate products representing
more than 180,000 bpd of our refinery feedstocks. See "Factors Affecting
Operating Results" and "Factors Affecting Comparability" below.

Factors Affecting Operating Results

     Our earnings and cash flow from operations are primarily affected by the
relationship between refined product prices and the prices for crude oil and
other feedstocks. The cost to acquire feedstocks and the price of refined
products ultimately sold depends on numerous factors beyond our control,
including the supply of, and demand for, crude oil, gasoline and other refined
products which, in turn, depend on, among other factors, changes in domestic and
foreign economies, weather conditions, domestic and foreign political affairs,
production levels, the availability of imports, the marketing of competitive
fuels and the extent of government regulation. While our net sales and operating
revenues fluctuate significantly with movements in industry crude oil prices,
such prices do not generally have a direct long-term relationship to net
earnings. Crude oil price movements may impact net earnings in the short term
because of fixed price crude oil purchase commitments. The effect of changes in
crude oil prices on our operating results is influenced by the rate at which the
prices of refined products adjust to reflect such changes.

     Feedstock and refined product prices are also affected by other factors,
such as product pipeline capacity, local market conditions and the operating
levels of competing refineries. Crude oil and other feedstock costs and the
price of refined products have historically been subject to wide fluctuation.
Expansion of existing facilities and installation of additional refinery crude
distillation and upgrading facilities, price volatility, international political
and


                                       17

<PAGE>

economic developments and other factors beyond our control are likely to
continue to play an important role in refining industry economics. These factors
can impact, among other things, the level of inventories in the market resulting
in price volatility and a reduction in product margins. Moreover, the industry
typically experiences seasonal fluctuations in demand for refined products, such
as for gasoline during the summer driving season and for home heating oil during
the winter, primarily in the Northeast.

     In order to assess our operating performance, we compare our gross margin
(net sales and operating revenue less cost of sales) against an industry gross
margin benchmark. The industry gross margin is calculated by assuming that three
barrels of benchmark light sweet crude oil is converted, or cracked, into two
barrels of conventional gasoline and one barrel of high sulfur diesel fuel. This
is referred to as the 3/2/1 crack spread. Since we calculate the benchmark
margin using the market value of U.S. Gulf Coast gasoline and diesel fuel
against the market value of West Texas Intermediate crude oil, we refer to the
benchmark as the Gulf Coast 3/2/1 crack spread, or simply, the Gulf Coast crack
spread. The Gulf Coast crack spread is expressed in dollars per barrel and is a
proxy for the per barrel margin that a sweet crude oil refinery situated on the
Gulf Coast would earn assuming it produced and sold the benchmark production of
conventional gasoline and high sulfur diesel fuel. As explained below, each of
our refineries has certain feedstock cost and/or product value advantages as
compared to the benchmark refinery and as a result, our gross margin per barrel
of throughput generally exceeds the Gulf Coast crack spread.

     Our Port Arthur and Hartford refineries are able to process significant
quantities of sour and heavy sour crude oil that has historically cost less than
West Texas Intermediate crude oil. We measure the cost advantage of heavy sour
crude oil by calculating the spread between the value of Maya crude oil, a heavy
crude oil produced in Mexico, to the value of West Texas Intermediate crude oil,
a light crude oil. We use Maya for this measurement because a significant amount
of our heavy sour crude oil throughput is Maya. We measure the cost advantage of
sour crude oil by calculating the spread between the value of West Texas Sour
crude oil to the value of West Texas Intermediate crude oil. In addition, since
we are able to source both domestic pipeline crude oil and foreign tanker crude
oil to each of our three refineries, the value of foreign crude oil relative to
domestic crude oil is also an important factor affecting our operating results.
Since many foreign crude oils are priced relative to the market value of a
benchmark North Sea crude oil known as Dated Brent, we also measure the cost
advantage of foreign crude oil by calculating the spread between the value of
Dated Brent crude oil to the value of West Texas Intermediate crude oil.

     As part of the Port Arthur heavy oil upgrade project, we lease our crude,
vacuum and other ancillary refinery units to our affiliate, Port Arthur Coker
Company, but we currently utilize approximately 20%, or 50,000 bpd, of crude
distillation capacity through a processing arrangement. Port Arthur Coker
Company also pays us a fee for providing certain services and supplies. Port
Arthur Coker Company produces primarily intermediate feedstocks, which are sold
to us at fair market value for further processing into higher value finished
products. The utilization of intermediate feedstocks purchased from Port Arthur
Coker Company, rather than crude oil, causes a variance from the benchmark crack
spreads because these intermediate feedstocks are generally more expensive than
the benchmark West Texas Intermediate crude oil. However, this variance is
partially offset by lease, service and supply fees paid to us by Port Arthur
Coker Company. These payments, which provide a reliable source of cash flow that
is not market sensitive, increase our revenues and reduce our operating costs.

                                       18

<PAGE>


     The sales value of our production is also an important consideration in
understanding our results. We produce a high volume of premium products, such as
premium and reformulatedgasoline, low sulfur diesel fuel, jet fuel, and
petrochemical products that carry a sales value significantly greater than that
for the products used to calculate the Gulf Coast crack spread. In addition,
products produced by our Midwest refineries are generally of higher value than
similar products produced on the Gulf Coast due to the fact that the Midwest
consumes more product than it produces, thereby creating a competitive advantage
for Midwest refiners that can produce and deliver refined products at a cost
lower than importers of refined product into the region. This advantage is
measured by the excess of the Chicago crack spread over the Gulf Coast crack
spread. The Chicago crack spread is determined by replacing the published Gulf
Coast product values in the Gulf Coast crack spread with published Chicago
product values.

     Another important factor affecting operating results is the relative
quantity of higher value transportation fuels and petrochemical products
compared to the production of residual fuel oil and other by-products such as
petroleum coke and sulfur. Our Midwest refineries produce a product slate that
is of significantly higher value than the products used to calculate the Gulf
Coast crack spread. At our Hartford refinery, this added value is driven
primarily by the competitive location advantage discussed above. Our Lima
refinery benefits from its mid-continental location, in addition to the fact
that it produces a greater percentage of high value transportation fuels as a
result of processing a predominantly sweet crude oil slate.

     Our operating cost structure is also important to our profitability. Major
operating costs include energy, employee labor, processing fees paid to Port
Arthur Coker Company, maintenance, including contract labor, and environmental
compliance. By far, the predominant variable cost is energy and the most
important benchmark for energy costs is the value of natural gas. Because the
complexity of the Port Arthur refinery complex and its ability to process
greater volumes of heavy sour crude oil increased significantly as a result of
the heavy oil upgrade project, the complex now has a higher operating cost
structure, primarily related to energy and labor. However, our share of these
operating costs has been reduced due to the lease and service fees paid to us by
Port Arthur Coker Company in accordance with the intercompany agreements.

     Consistent, safe and reliable operations at the refineries are a key to our
financial performance. Unplanned downtime of our refinery assets generally
results in lost margin opportunity, increased maintenance expense and a
temporary increase in working capital investment and related inventory position.
If we choose to hedge the incremental inventory position, we are subject to
market and other risks normally associated with hedging activities. The
financial impact of planned downtime, such as major turnaround maintenance, is
mitigated through a diligent planning process that considers such things as
margin environment, availability of resources to perform the needed maintenance
and feedstock logistics.

     The nature of our business leads us to maintain a substantial investment in
petroleum inventories. Since petroleum feedstocks and products are essentially
commodities, we have no control over the changing market value of our
investment. We manage the impact of commodity price volatility on our
hydrocarbon inventory position by, among other methods, determining a volumetric
exposure level that we consider to be appropriate and consistent with normal
business operations. This target inventory position, which includes both titled
inventory and fixed price purchase and sale commitments, is generally not
hedged. To the extent that our inventory position deviates from the target
level, we consider risk mitigation activities usually through the purchase or
sale of futures contracts on the New York Mercantile Exchange or NYMEX. Our
hedging activities carry all of the usual time, location and product grade basis
risks associated



                                       19

<PAGE>

with hedging activities generally. Because our titled inventory is valued under
the last-in, first-out costing method, price fluctuations on our target level of
titled inventory have very little effect on our financial results unless the
market value of our target inventory is reduced below cost. However, our
financial results are affected by price movements on the target level of fixed
price purchase and sale commitments, which, when netted, amount to a long
hydrocarbon inventory position of approximately 6 million barrels.

Factors Affecting Comparability

     Our results compared to the comparable period of the prior year are
affected by the following events, which must be understood in order to assess
the comparability of our period to period financial performance.

     Port Arthur Heavy Oil Upgrade Project. In January 2001, the operations of
the heavy oil upgrade project at our Port Arthur refinery began. The project,
construction of which began in 1998, included new coking, hydrocracking, and
sulfur removal units and the expansion of the existing crude unit capacity to
250,000 bpd. The heavy oil upgrade project allows the refinery to process
primarily lower-cost, heavy sour crude oil. In the third quarter of 1999, we
sold a portion of the work in progress and certain other assets to our
affiliate, Port Arthur Coker Company. Port Arthur Coker Company financed and
completed the construction of the coking, hydrocracking, and sulfur removal
facilities. We completed the expansion of our crude unit capacity to 250,000 bpd
from 232,000 bpd and made certain other improvements to existing facilities.
Start-up of the project occurred in three stages, with the sulfur removal units
beginning operations in November 2000, the coker unit beginning operations in
December 2000 and the hydrocracker unit beginning operations in January 2001.
Performance and reliability testing of the project was completed in the third
quarter of 2001. Additional information regarding the heavy oil upgrade project
is included in our Annual Report on Form 10-K for the year ended December 31,
2000.

     We entered into agreements with Port Arthur Coker Company associated with
the refinery upgrade project and continuing operations as described in our
Annual Report on Form 10-K for the year ended December 31, 2000. These
agreements, and other factors, significantly impacted the comparability of the
Company's 2001 results with the results of 2000 as follows:

                                       20

<PAGE>

     .   Under the agreements, we lease our crude, vacuum and certain other
         ancillary units to Port Arthur Coker Company but currently utilize
         approximately 20%, or 50,000 bpd, of crude distillation capacity
         through a processing arrangement discussed below. Port Arthur Coker
         Company utilizes approximately 80%, or 200,000 bpd of our leased crude
         distillation capacity. Beginning in December 2000, we began receiving
         quarterly net lease payments from Port Arthur Coker Company for the
         lease of our crude, vacuum and other ancillary units as described
         above. Port Arthur Coker Company also pays us a fee for pipeline access
         and use of our refinery dock. The net effect of these lease payments
         is recorded in Net Sales and Operating Revenue and increases our gross
         margin accordingly.

     .   Port Arthur Coker Company produces predominantly intermediate
         feedstocks that are sold to us at their fair market value. The
         intermediate refined feedstocks are normally higher in price than
         crude oil because they have been partially refined. In 2000, prior to
         the start up of Port Arthur Coker Company, our feedstocks consisted
         primarily of crude oil.

     .   In order to efficiently process our crude oil throughput, we utilize a
         portion of Port Arthur Coker Company's equipment and pay a monthly
         processing fee. Payment of this fee began in December 2000 and is
         recorded as an operating expense.

     .   We also provide certain services and supplies to Port Arthur Coker
         Company including employee, maintenance, and energy costs. Beginning in
         December 2000, Port Arthur Coker Company reimburses us for these
         services at their fair market value. These fees are recorded as an
         offset to our operating expenses.

     Closure of Blue Island Refinery. In January 2001, we ceased operations at
the Blue Island refinery due to economic factors and a decision that the capital
expenditures necessary to produce low sulfur transportation fuels required by
recently adopted Environmental Protection Agency regulations could not produce
an acceptable return on investment. We continue to utilize our petroleum
products storage facility at the refinery site to supply products to the Chicago
and other Midwest markets from our operating refineries. Since the Blue Island
refinery operation has been only marginally profitable in recent years and since
we will continue to operate a petroleum products storage and distribution
business from the Blue Island site, the closure of the refinery is not expected
to have a significant negative impact on net income or cash from operations. The
only significant effect on net income and cash flow will result from the actual
shutdown process and subsequent environmental site remediation as discussed
below.

     Management adopted an exit plan that detailed the shutdown of the process
units at the refinery and the subsequent environmental remediation of the site.
The shutdown of the process units was completed during the first quarter of
2001. We are currently in discussions with the Illinois Environmental Protection
Agency concerning an investigation of the site and a remediation program that
would allow for redevelopment of the site for other manufacturing uses at the
earliest possible time. Until the site remediation plan is finalized, it is not
possible to estimate the completion date for the remediation, but we anticipate
that the remediation activities will continue for an extended period of time.

     A pre-tax charge of $150.0 million was recorded in the first quarter of
2001 and an additional charge of $17.2 million was recorded in the third quarter
of 2001. The original charge included $92.5 million of non-cash asset write-offs
in excess of realizable value and a reserve for future costs of $57.5 million,
consisting of $12.0 million for severance, $26.4 million for the ceasing of
operations, preparation of the plant for permanent closure and equipment
remediation and $19.1 million for site remediation and other environmental
matters. The third quarter charge of $17.2 million included an adjustment of
$5.6 million to the asset write-off to reflect changes in realizable asset value
and an increase of $11.6 million related to a continued evaluation of expected
future expenditures as detailed below. We expect to spend approximately $40
million in 2001 related to the $69.1 million adjusted reserve for future costs,
with the majority of the remainder to be



                                       21

<PAGE>

spent over the next several years. The following schedule summarizes the
restructuring reserve balance and net cash activity as of September 30, 2001:

<TABLE>
<CAPTION>
                                                                                        Reserve at
                                                      Initial    Reserve    Net Cash    September
                                                      Reserve  Adjustment    Outlay       30,2001
                                                      -------  ----------   --------   ----------
<S>                                                   <C>      <C>          <C>        <C>
  Employee severance ..........................       $  12.0  $      0.7       10.5          2.2
  Plant closure/equipment remediation .........          26.4         6.3       16.1         16.6
  Site remediation/environmental matters ......          19.1         4.6        1.7         22.0
                                                      -------  ----------   --------   ----------
                                                      $  57.5  $     11.6     $ 28.3         40.8
                                                      =======  ==========   ========   ==========
</TABLE>

     The site remediation and environmental reserve takes into account costs
that we can reasonably estimate at this time. As the site remediation plan is
finalized and work performed, adjustments of the estimate may be necessary. We
anticipate that remediation activities will continue for an extended period of
time. We are also evaluating other potential environmental risk management
options in order to quantify more precisely the cost of remediation of the site
and to provide the governmental agencies financial assurance that, once begun,
remediation of the site will be completed in a timely and prudent manner.

     The Blue Island refinery employed 297 employees, both hourly (covered by
collective bargaining agreements) and salaried, approximately 280 of whom were
terminated during the first nine months of 2001. The remaining employees are all
salaried employees and the majority of them will terminate employment within the
year as the shutdown progresses.

Industry Outlook

     Our earnings depend largely on refining industry margins, which have been
and continue to be volatile. The cost of crude oil and intermediate feedstocks
we purchase and the prices of refined products we sell have fluctuated widely in
the past. Crude oil, intermediate feedstocks and refined product prices depend
on numerous factors beyond our control. While it is impossible to predict
refining margins due to the uncertainties associated with global crude oil
supply and domestic demand for refined products, we believe that refining
margins for United States refineries will generally remain above those
experienced in the period 1995 through 2000 as growth in demand for refining
products in the United States, particularly transportation fuels, continues to
exceed the ability of domestic refiners to increase capacity. The review of 2001
year-to-date refining industry margins summarized below gives some indication of
the volatility that exists in the industry.

     Over the first five months of 2001, the market price of distillate relative
to crude oil was above average due to low industry inventories and strong
consumer demand brought about by the relatively cold winter weather in the
northeast United States and eastern Canada and high natural gas prices which led
to an increase in industrial users switching from natural gas to fuel oil. In
addition, gasoline margins were above average, primarily because substantial
scheduled and unscheduled refinery maintenance turnaround activity in the United
States in late 2000 and early 2001 resulted in inventories that did not increase
in a manner typically experienced during the winter. The increased demand for
refined products due to the relatively cold winter and the decreased supply due
to high turnaround activity, led to increasing refining margins during the first
five months of 2001. As a result, the average margin achieved over the first
half of 2001 was approximately twice the average for the first six month period
over the last four years.



                                       22

<PAGE>

     During the ensuing four months of 2001 the refining markets were extremely
volatile. During June and July 2001, refining margins declined from the highs
experienced earlier in the year. This decline was largely the result of
increasing product inventories due to high refinery production rates, excessive
product import levels and slowing consumer demand. The healthy refining margins
realized in early 2001 led refiners to postpone scheduled turnarounds in order
to maximize utilization rates. Import levels increased because of high domestic
product prices relative to foreign product prices. Growth in consumer demand
slowed as a result of high prices and a weakening economy. However, refining
margins strengthened in August due to other refiners' unplanned downtime and
decisions to undertake delayed maintenance turnarounds and due to lower product
imports. The terrorist attacks on September 11th created a downward spiral of
refining margins, lowering demand for distillates, in particular jet fuel, and
gasoline. The lower demand has led to higher gasoline and distillate
inventories.

     Average discounts for sour and heavy sour crude oil increased in the first
nine months of 2001 from already favorable 2000 levels due to increasing
worldwide production of sour and heavy sour crude oil relative to production of
light sweet crude oil, coupled with continuing demand for light sweet crude oil.
In April 2001, the discount for heavy sour crude oil versus West Texas
Intermediate widened to more than double historical averages. Although the heavy
sour crude oil discount to West Texas Intermediate crude oil has narrowed from
these record highs, the discount continues to exceed historic levels. Sweet
crude oil continues to trade at a premium to West Texas Sour due to continued
high demand for sweet crude oil resulting from the more stringent fuel
specifications implemented in the United States and Europe and the higher
margins for light products.

     The price of natural gas, which is a significant component of our overall
operating costs, peaked at over $10 per million btu in late 2000 and early 2001,
but has fallen to approximately $3 per million btu. While certainly more
favorable than recent record levels, we expect the price of natural gas to
result in an increase in per-barrel cash operating costs for 2001 relative to
2000. As production rates and inventories of natural gas continue to increase,
we expect prices will remain at levels well below the record highs seen in the
first quarter of 2001.

        In the near term, we anticipate that refining margins will remain at
slightly depressed levels as the country and the world wait to see what will
happen in the war against terrorism both here in the United States and in the
Middle East. The attacks and the subsequent retaliation have raised questions
about gasoline and distillate demand and crude oil supply, particularly the
supply from the Middle East. Additionally, the depth of economic recession in
the United States, and the decline in consumer spending confidence and the weak
industrial sector will curtail demand for petroleum products. We expect the
Chicago crack spread to remain strong relative to the Gulf Coast crack spread,
although well below the highs seen earlier this year, due to the narrowed supply
caused by an extended outage of a third party Chicago refinery's crude unit.

     In the long-term, we expect refined product supply and demand balances to
tighten worldwide as growth in demand for refined products is expected to exceed
net capacity growth, particularly for transportation fuels. A portion of the
supply growth due to new capacity built by foreign refiners and the continued
de-bottlenecking and expansion of existing refineries will likely be offset by
more stringent environmental specifications and refinery closures resulting from
capital requirements to meet worldwide low-sulfur gasoline and diesel
specifications. We expect that the worldwide growth in production of sour and
heavy sour crude oil will continue to exceed increases in the production of
light sweet crude oil and that this, when coupled with the continuing demand for
light sweet crude oil, will support a wide spread between the prices of



                                       23

<PAGE>

light sweet and heavy sour crude oil. In summary, we believe refining margins in
the United States will benefit from continuing favorable supply and demand
fundamentals.


                                       24

<PAGE>

Results of Operations

     The following tables reflects our financial and operating highlights for
the three- and nine-month periods ended September 30, 2000 and 2001.

<TABLE>
<CAPTION>
              Financial Results                 For the Three Months Ended           For the Nine Months Ended
       (in millions, except as noted)                  September 30,                       September 30,
                                               ----------------------------        ----------------------------
                                                  2000              2001              2000              2001
                                               ----------        ----------        ----------        ----------
<S>                                            <C>               <C>               <C>               <C>
Net sales and operating revenues               $  2,032.6        $  1,701.2        $  5,312.4        $  5,265.0
Cost of sales                                     1,862.8           1,489.3           4,762.7           4,574.6
                                               ----------        ----------        ----------        ----------
   Gross margin                                     169.8             211.9             549.7             690.4
Operating expenses                                  115.0              85.5             327.9             265.7
General and administrative expenses                  12.3              14.9              34.9              42.0
                                               ----------        ----------        ----------        ----------
   Adjusted EBITDA /(1)/                             42.5             111.5             186.9             382.7
Depreciation & amortization                          18.9              17.9              52.2              52.5
Refinery restructuring and other charges               --             (26.2)               --            (190.2)
                                               ----------        ----------        ----------        ----------
   Operating income                                  23.6              67.4             134.7             140.0
Interest expense and finance income, net            (15.8)            (14.9)            (46.3)            (47.3)
Income tax provision                                 (0.2)            (21.7)             (0.6)            (24.9)
                                               ----------        ----------        ----------        ----------
   Net income before extraordinary item               7.6              30.8              87.8              67.8
Gain on repurchase of long-term debt                   --               0.5                --               0.5
                                               ----------        ----------        ----------        ----------
   Net income available to common
     stockholders                              $      7.6        $     31.3        $     87.8        $     68.3
                                               ==========        ==========        ==========        ==========
</TABLE>


(1)Earnings before interest, income taxes, depreciation, and amortization and
excluding the refinery restructuring and other charges

<TABLE>
<CAPTION>
             Market Indicators                          For the Three Months     For the Nine Months Ended
   (dollars per barrel, except as noted)                 Ended September 30,            September 30,
                                                       ---------------------------------------------------
                                                          2000        2001           2000        2001
                                                          ----        ----           ----        ----
<S>                                                    <C>          <C>            <C>         <C>
West Texas Intermediate (WTI) crude oil .......         $   31.75   $   26.81      $   29.85   $   27.84
Crack Spreads (3/2/1):
     Gulf Coast ...............................         $    4.37   $    3.41      $    4.32   $    4.98
     Chicago ..................................         $    5.09   $    9.21      $    5.92   $    9.04
Crude Oil Differentials:
     WTI less WTS (sour) ......................         $    1.94   $    2.02      $    1.97   $    3.11
     WTI less Maya (heavy sour) ...............         $    7.39   $    7.63      $    6.49   $    9.57
     WTI less Dated Brent (foreign) ...........         $    1.19   $    1.43      $    1.76   $    1.68
Natural gas (per mmbtu) .......................         $    4.55   $    3.01      $    3.50   $    4.90

<CAPTION>
                                                       For the Three Months       For the Nine Months Ended
Selected Volumetric and Per Barrel Data                 Ended September 30,             September 30,
(in thousands of barrels per day, except as noted)    -----------------------     ------------------------
                                                          2000        2001           2000        2001
                                                          ----        ----           ----        ----
<S>                                                   <C>           <C>            <C>         <C>
Production ....................................             512.3       434.9          467.6       442.6

Crude oil throughput ..........................             531.8       252.4          454.4       258.6
PACC intermediate throughput ..................                --       157.8             --       174.3
                                                        ---------   ---------      ---------   ---------
     Total throughput .........................             531.8       410.2          454.4       432.9

Per barrel of throughput (in dollars):
Gross margin ..................................         $    3.47   $    5.62      $    4.42   $    5.84
Operating expenses ............................         $    2.35   $    2.27      $    2.63   $    2.25
</TABLE>

                                       25

<PAGE>

<TABLE>
<CAPTION>
                                                   Three Months Ended                              Three Months Ended
                                                    September, 2000                                September 30, 2001
                                       -------------------------------------------    --------------------------------------------
      Selected Volumetric Data           Port                            Total        Port                              Total
  (in thousands of barrels per day)     Arthur    Midwest      Total     Percent      Arthur     Midwest      Total    Percent
                                       ---------  ---------- ----------  ---------    ----------  ---------- ---------- ----------
<S>                                    <C>        <C>        <C>         <C>       <C>         <C>        <C>        <C>
Feedstocks:
 Crude oil throughput
   Sweet                                     5.7      221.4      227.1      45%        --         157.8      157.8      37%
   Light/medium sour                       207.0       39.3      246.3      48%         4.9        49.4       54.3      13%
   Heavy sour                               34.6       23.8       58.4      12%        33.6         6.7       40.3      10%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total crude oil                       247.3      284.5      531.8     105%        38.5       213.9      252.4      60%
 PACC intermediate throughput               --         --         --        --        157.8        --        157.8      37%
 Unfinished and blendstocks                (16.8)      (5.9)     (22.7)     (5)%       17.9        (5.0)      12.9       3%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total feedstocks                      230.5      278.6      509.1     100%       214.2       208.9      423.1     100%
                                       =========  ========== ==========  ========= ==========  ========== ========== ==========

Production:
 Light Products:
   Conventional gasoline                    85.9      127.0      212.9      42%        82.2       103.3      185.5      43%
   Premium and reformulated gasoline         9.1       39.6       48.7      10%        24.0        20.2       44.2      10%
   Diesel fuel                              68.6       61.4      130.0      25%        76.1        40.5      116.6      27%
   Jet fuel                                 17.0       24.4       41.4       8%        17.9        25.8       43.7      10%
   Petrochemical feedstocks                 24.0       12.0       36.0       7%        17.2         9.7       26.9       6%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total light products                  204.6      264.4      469.0      92%       217.4       199.5      416.9      96%
 Residual oil                               16.7        6.6       23.3       4%         4.6         1.7        6.3       1%
 Petroleum coke and sulfur                  11.7        8.3       20.0       4%         4.9         6.8       11.7       3%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total production                      233.0      279.3      512.3     100%       226.9       208.0      434.9     100%
                                       =========  ========== ==========  ========= ==========  ========== ========== ==========
</TABLE>



<TABLE>
<CAPTION>
                                                    Nine Months Ended                            Nine Months Ended
                                                   September 30, 2000                           September 30, 2001
                                       ------------------------------------------- -----------------------------------------
      Selected Volumetric Data           Port                            Total        Port                             Total
  (in thousands of barrels per day)     Arthur    Midwest      Total     Percent     Arthur     Midwest      Total    Percent
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
<S>                                    <C>        <C>        <C>         <C>       <C>         <C>        <C>        <C>
Feedstocks:
 Crude oil throughput
   Sweet                                     4.8      205.8      210.6      45%        --         147.0      147.0      33%
   Light/medium sour                       149.9       44.6      194.5      42%        11.6        60.7       72.3      16%
   Heavy sour                               32.6       16.7       49.3      11%        33.4         5.9       39.3       9%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total crude oil                       187.3      267.1      454.4      98%        45.0       213.6      258.6      58%
 PACC intermediate throughput               --         --         --        --        174.3        --        174.3      40%
 Unfinished and blendstocks                 10.5       (1.7)       8.8       2%        10.8        (3.5)       7.3       2%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total feedstocks                      197.8      265.4      463.2     100%       230.1       210.1      440.2     100%
                                       =========  ========== ==========  ========= ==========  ========== ========== ==========

Production:
 Light Products:
   Conventional gasoline                    71.0      119.6      190.6      41%        81.9       100.6      182.5      41%
   Premium and reformulated gasoline        18.2       40.6       58.8      12%        24.6        22.5       47.1      11%
   Diesel fuel                              54.6       58.7      113.3      24%        74.4        44.2      118.6      27%
   Jet fuel                                 16.1       20.9       37.0       8%        18.6        23.2       41.8       8%
   Petrochemical feedstocks                 23.5       12.7       36.2       8%        18.9        10.1       29.0       7%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total light products                  183.4      252.5      435.9      93%       218.4       200.6      419.0      94%
 Residual oil                                7.5        6.4       13.9       3%         4.6         2.6        7.2       2%
 Petroleum coke and sulfur                  10.2        7.6       17.8       4%         9.5         6.9       16.4       4%
                                       ---------  ---------- ----------  --------- ----------  ---------- ---------- ----------
     Total production                      201.1      266.5      467.6     100%       232.5       210.1      442.6     100%
                                       =========  ========== ==========  ========= ==========  ========== ========== ==========
</TABLE>

 Blue Island refinery (included in      Three months ended     Nine months ended
 data above):                             September 30,          September 30,
                                       ---------------------  ------------------
                                          2000       2001        2000     2001
                                       ---------  ----------  --------- --------
     Total feedstocks                       73.6        -        69.8        5.8
     Total Production                       73.3        -        69.6        5.7




                                       26

<PAGE>

     Overview. Net income increased $23.7 million to $31.3 million in the third
quarter of 2001 from $7.6 million in the corresponding period in 2000. Operating
income increased $43.8 million to $67.4 million in the third quarter of 2001
from $23.6 million in the corresponding period in 2000. Net income decreased
$19.5 million to $68.3 million in the first nine months of 2001 from $87.8
million in the corresponding period in 2000. Operating income increased $5.3
million to $140.0 million in the first nine months of 2001 from $134.7 million
in the corresponding period in 2000. Operating income included a $26.2 million
and $190.2 million pre-tax refinery restructuring and other charges for the
third quarter and first nine months of 2001, respectively, representing
non-recurring charges. Operating income, excluding the refinery restructuring
and other charges, increased $70.0 million to $93.6 million and increased $195.5
million to $330.2 million in the third quarter and first nine months of 2001,
respectively. The increases in operating income, excluding the refinery
restructuring and other charges, were principally due to strong market
conditions partially offset by operational issues as discussed below. The
operating results for 2001 compared to 2000 were also affected by the completion
and operation of the heavy oil upgrade project at the Port Arthur refinery. See
"Factors Affecting Comparability" and "Factors Affecting Operating Results" for
a detailed discussion of how the heavy oil upgrade project has affected our
results.

     Net Sales and Operating Revenue. Net sales and operating revenues decreased
$331.4 million, or 16%, to $1.701 billion in the third quarter of 2001 from
$2.033 billion in the corresponding period in 2000. Net sales and operating
revenues decreased $47.4 million, or 1%, to $5.265 billion in the first nine
months of 2001 from $5.312 billion in the corresponding period in 2000. These
decreases were mainly attributable to steep declines in petroleum product prices
particularly after the September 11th terrorist attacks. In the third quarter
our average sales price of gasoline and distillates decreased approximately
$3-$4 per barrel.

     Gross Margin. Gross margin increased $42.1 million to $211.9 million in the
third quarter of 2001 from $169.8 million in the corresponding period in 2000.
Gross margin increased $140.7 million to $690.4 million in the first nine months
of 2001 from $549.7 million in the corresponding period in 2000. The increase in
the third quarter was principally driven by strong Chicago crack spreads
partially offset by lower Gulf Coast crack spreads and plant downtime. The
increase in the first nine months was principally due to historically strong
market conditions in the first half of the year and continued strong market
conditions in the Midwest region through the third quarter, partially offset by
planned and unplanned refinery downtimes. The strong crack spreads in the first
half of the year were driven by strong demand going into the summer driving
season accompanied by low domestic inventory levels in the first half of the
year. The strong market conditions in the Midwest for the third quarter were
driven by decreases in supply caused by an extended outage at a third party
Chicago refinery's crude unit.

     Gross margin was also favorably impacted by the improvement in the sour and
heavy sour crude oil discounts for the first nine months of 2001 compared to the
corresponding periods in 2000, but was partially offset by the use of more
expensive intermediate feedstocks for approximately 80% of our throughput at our
Port Arthur refinery. Gross margin also increased due to lease, supplies and
service revenue generated by our intercompany agreements with Port Arthur Coker
Company. Partially offsetting the improvements to gross margin was the effects
of producing a lower amount of higher-value products at our Port Arthur refinery
due to the changes in product mix as discussed in "Factors Affecting Operating
Results" above

                                       27

<PAGE>

     Our Port Arthur refinery financial results were greatly impacted in the
third quarter and first nine months of 2001 compared to 2000 by the completion
of the heavy oil upgrade project. The feedstock throughput rates for our Port
Arthur operations reflected the change in operations due to the completion of
the heavy oil upgrade project and start up of operations at Port Arthur Coker
Company. Feedstock throughput rates were 196,300 bpd and 219,300 bpd for the
third quarter and first nine months of 2001, respectively. Of these feedstock
throughput rates, 38,500 bpd and 45,000 bpd for the third quarter and first nine
months of 2001, respectively, were crude oil. The remainder of the feedstock
throughput was intermediate feedstock purchased from Port Arthur Coker Company.
Feedstock throughput rates in the third quarter of 2001 were restricted due to a
lightning strike in early May, which limited the crude unit rate until the crude
unit was shutdown in early July for eight days to repair the damage caused by
the lightning strike. Both the crude unit rate restriction and subsequent
downtime for repairs lowered feedstock throughput rates by approximately 27,000
bpd during the third quarter. The crude unit, of which approximately 80% of the
capacity is utilized by Port Arthur Coker Company, ran at close to its capacity
of 250,000 bpd in August and September of 2001. Feedstock throughput rates in
the first nine months of 2001 were restricted due to the lightning strike and
subsequent repairs plus restrictions on the crude unit as downstream process
units were in start-up operations during the first quarter. In the first quarter
of 2001, the Port Arthur refinery performed a planned maintenance turnaround on
its alkylation unit, which had only a minor impact on production. In the third
quarter of 2000, crude oil throughput rates at the Port Arthur refinery averaged
247,300 bpd following the planned maintenance turnaround and upgrade in May of
2000, which increased crude capacity from 232,000 bpd to 250,000 bpd.

     In the third quarter of 2001, both the Lima and Hartford refineries
experienced some crude oil throughput restrictions, but overall crude oil
throughput rates were flat with prior year rates. In the third quarter of 2001,
both the Hartford and Lima refineries shut down their coker units for repairs
that had minimal impacts on production and crude oil throughput. Midwest crude
oil throughput rates in the first nine months of 2001 were below capacity
principally due to crude oil delivery delays to the Lima refinery caused by bad
weather in the Gulf Coast, unplanned downtime at the Hartford refinery for coker
unit repairs, and the closure of the Blue Island refinery on January 31, 2001.
In the first nine months of 2000, Midwest crude oil throughput rates were
lowered by planned restrictions due to weak margin conditions, unplanned
downtime at the Lima refinery due to two electrical outages and a failed
compressor, and unplanned downtime at the Blue Island refinery, which required
maintenance on its vacuum and crude unit. In March 2001, the Lima refinery
performed a month-long maintenance turnaround on the coker and isocracker units.

     Operating Expenses. Operating expenses decreased $29.5 million to $85.5
million in the third quarter of 2001 from $115.0 million in the corresponding
period in 2000. Operating expenses decreased $62.2 million to $265.7 million in
the first nine months of 2001 from $327.9 million in the corresponding period in
2000. The decrease in the third quarter was principally due to the supply and
service fees collected from Port Arthur Coker Company based on the intercompany
agreements, lower energy costs at all of the refineries, and the absence of Blue
Island refinery expenses in 2001. The decrease for the first nine months of 2001
was mainly attributable to the collection of the supply and service fees from
Port Arthur Coker Company and the absence of Blue Island refinery expenses
partially offset by higher repair and maintenance expense at the Hartford
refinery and higher energy costs at the Lima refinery. The Hartford refinery
incurred the additional repair and maintenance expenses for the above-mentioned
coker unit repairs.

                                       28

<PAGE>

     As evidenced by the significant increases in the average natural gas price,
energy costs increased significantly in 2001. Our exposure to this increase was
limited in 2001 due to the sale of a significant amount of our Port Arthur
refinery energy costs to Port Arthur Coker Company.

     General and Administrative Expenses. General and administrative expenses
increased $2.6 million to $14.9 million in the third quarter of 2001 from $12.3
million in the corresponding period in 2000. General and administrative expenses
increased $7.1 million to $42.0 million in the first nine months of 2001 from
$34.9 million in the corresponding period in 2000. These increases were
principally due to a higher incentive bonus accrual in 2001 and expenses related
to the planning phase of a new financial information system installation.

     Refinery Restructuring and Other Charges. Refinery restructuring and other
charges consisted of, $167.2 million related to the January, 2001 closure of our
Blue Island, Illinois refinery, a $14.0 million charge related to the
environmental liability for previously-owned retail properties, and a $9.0
million charge related to the write-off of idled coker units at the Port Arthur
refinery. See "Factors Affecting Comparability" for additional information on
the Blue Island refinery closure. The retail environmental charge of $14.0
million represents a change in estimate relative to the Company's clean up
obligation regarding the discontinued retail division. More complete information
concerning site by site clean up plans and changing postures of state regulatory
agencies prompted the change in estimate.

     In September 2001, the Company incurred a charge of $5.8 million related to
the net asset value of the idled coker units at the Port Arthur refinery. The
two coker units have not been in use since the start-up of the new coker complex
at the Port Arthur Coker Company in December 2000. The Company believes that an
alternative use of the coker units is not probable at this time. The Company
also accrued $3.2 million for future environmental clean-up costs related to the
site.

     Depreciation and Amortization. Depreciation and amortization expenses
decreased $1.0 million to $17.9 million in the third quarter of 2001 from $18.9
million in the corresponding period in 2000. Depreciation and amortization
expenses increased $0.3 million to $52.5 million in the first nine months of
2001 from $52.2 million in the corresponding period in 2000. The decrease in the
third quarter was principally due to the absence of depreciation for the Blue
Island refinery after its January 2001 closure. The slight increase in the first
nine months of 2001 was principally attributable to higher depreciation in 2001
due to the completion of the heavy oil upgrade project and higher amortization
associated with a second quarter 2000 Port Arthur refinery turnaround. These
increases were almost completely offset by the absence of depreciation for the
Blue Island refinery in 2001.

     Interest Expense and Finance Income, net. Interest expense and finance
income, net decreased $0.9 million to $14.9 million in the third quarter of 2001
from $15.8 million in the corresponding period in 2000. Interest expense and
finance income, net increased $1.0 million to $47.3 million in the first nine
months of 2001 from $46.3 million in the corresponding period in 2000. The
decrease in the third quarter was principally due to lower interest rates on our
floating rate loan partially offset by lower capitalized interest in 2001. The
increase in the first nine months was principally associated with lower
capitalized interest in 2001. In the first nine months of 2000, a portion of
interest expense was capitalized as part of the heavy oil upgrade project. The
first nine months of 2001 do not include any interest capitalization for the
heavy oil

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<PAGE>

upgrade project since the project was substantially in service and operational
at the beginning of 2001.

     Income Tax Provision. Income tax provision increased $21.5 million to $21.7
million in the third quarter of 2001 from $0.2 million in the corresponding
period in 2000. Income tax provision increased $24.3 million to $24.9 million in
the first nine months of 2001 from $0.6 million in the corresponding period in
2000. The increase for the third quarter was principally due to an increase in
pretax income. The increase for the first nine months was principally due to an
increase in pretax income together with the complete reversal of our remaining
tax valuation allowance in the first quarter of 2001. Our pretax earnings are
now generally fully subject to income taxes.

Liquidity and Capital Resources

Cash Flows from Operating Activities

     Net cash provided by operating activities for the nine months ended
September 30, 2001 was $212.2 million compared to $109.7 million in the
year-earlier period. The improvement in net cash provided by operating
activities principally resulted from improved operating results. Working capital
as of September 30, 2001 was $415.2 million, a 1.80-to-1 current ratio, versus
$261.7 million as of December 31, 2000, a 1.43-to-1 current ratio.

     In general, our short-term working capital requirements fluctuate with the
price and payment terms of crude oil and refined petroleum products. We have an
amended and restated credit agreement which provides for the issuance of letters
of credit up to the lesser of $650 million or the amount of a borrowing base
calculated with respect to our cash and eligible cash equivalents, eligible
investments, eligible receivables, eligible petroleum inventories, paid but
unexpired letters of credit, and net obligations on swap contracts. In August
2001, the credit agreement was amended and restated for a period of two years
through August 2003. The credit agreement provides for direct cash borrowings up
to $50 million. Borrowings under the credit agreement are secured by a lien on
substantially all of our cash and cash equivalents, receivables, crude oil and
refined product inventories and trademarks. The borrowing base associated with
such facility at September 30, 2001 was $752.9 million with $342.4 million of
the facility utilized for letters of credit. As of September 30, 2001, there
were no direct cash borrowings under the credit agreement.

     The credit agreement contains covenants and conditions that, among other
things, limit our dividends, indebtedness, liens, investments and contingent
obligations. We are also required to comply with certain financial covenants,
including the maintenance of working capital of at least $150 million, the
maintenance of tangible net worth of at least $150 million, and the maintenance
of minimum levels of balance sheet cash (as defined therein) of $75 million at
all times. The covenants also provide for a cumulative cash flow test that from
July 1, 2001 must not be less than zero. We were in compliance with all
financial covenants as of September 30, 2001.

     In addition, we had three separate cash-collateralized facilities with
certain lenders: (i) a $75 million letter of credit facility for hydrocarbon
purchases, (ii) a $50 million facility for issuing letters of credit to Foster
Wheeler in connection with the heavy oil upgrade project, and (iii) a $20
million letter of credit facility for non-hydrocarbon items. The $50 million
facility expired on April 30, 2001, and the $75 million and $20 million
facilities expired on October 31, 2001.

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<PAGE>

There were no letters of credit issued against the $75 million facility and $7.8
million against the $20 million facility as of September 30, 2001.

     In 1999, we sold crude oil linefill in the pipeline system supplying the
Lima refinery. An agreement is in place that requires us to repurchase
approximately 2.4 million barrels of crude oil in this pipeline system in
September 2002 at market prices, unless extended by mutual consent. The Company
has hedged the price risk related to the repurchase obligations through the
purchase of exchange-traded futures contracts.

Cash Flows from Investing Activities

     Cash flows used in investing activities in the nine months ended September
30, 2001 were $90.3 million as compared to $133.6 million in the year-earlier
period. Capital expenditures were $61.2 million lower than the same period last
year, primarily due to the ramp-down of the heavy oil upgrade project.
Turnaround costs increased $17.5 million over last year, due to expenditures in
2001 for planned maintenance at the Port Arthur and Lima refineries.

     We classify our capital expenditures into two categories, mandatory and
discretionary. Mandatory capital expenditures, such as for turnarounds and
maintenance, are required to maintain safe and reliable operations or to comply
with regulations pertaining to soil, water and air contamination or pollution
and occupational, safety and health issues. We estimate that total mandatory
capital and turnaround expenditures will average approximately $115 million per
year over the next four years. This estimate includes the capital costs
necessary to comply with environmental regulations, except for Tier 2 gasoline
standards, on-road diesel regulations and the MACT II regulations described
below. Our total mandatory capital and refinery maintenance turnaround
expenditure budget is approximately $100 million in 2001, of which $60.9 million
has been spent as of September 30, 2001. Discretionary capital expenditures are
undertaken by us on a voluntary basis after thorough analytical review and
screening of projects based on the expected return on incremental capital
employed. Discretionary capital projects generally involve an expansion of
existing capacity, improvement in product yields and/or a reduction in operating
costs. We plan to fund both mandatory and discretionary capital expenditures
with cash flow from operations. Accordingly, total discretionary capital
expenditures may be less than budget if cash flow is lower than expected and
higher than budget if cash flow is better than expected. Our discretionary
capital expenditure budget is approximately $39 million in 2001, of which $29.5
million has been spent as of September 30, 2001. We currently plan to spend
approximately $40 million on discretionary capital projects in 2002.

     In addition to mandatory capital expenditures, we expect to incur
significant costs in order to comply with environmental regulations discussed
below. For example, the Environmental Protection Agency has promulgated new
regulations under the Clean Air Act that establish stringent sulfur content
specifications for gasoline and on-road diesel fuel designed to reduce air
emissions from the use of these products. The gasoline specifications, referred
to as the Tier 2 standards, have been enacted and will be phased in beginning in
2004, with full compliance required by January 1, 2006. Based on our preliminary
estimates, we believe that compliance with the Tier 2 gasoline standards will
require us to spend between $180 million and $225 million. More than 90% of the
projected investment is expected to be incurred during 2002 through 2004 with
the greatest concentration of spending occurring in 2003. The low sulfur highway
on-road diesel regulations will require a 97% reduction in the sulfur content of
diesel fuel sold for highway use by June 1, 2006, with full compliance by
January 1, 2010. The Environmental Protection Agency has also announced its
intention to review the sulfur content in diesel fuel sold to off-road
consumers. If regulations are promulgated to regulate the sulfur content of
off-road diesel, we expect the sulfur requirement to be either 500 ppm, which is
the current on-road limit, or 15 ppm, which will be the future on-road limit. If
the new off-road standard is 500 ppm, the capital expenditures necessary for us
to comply with the new diesel standards may be significantly reduced because our
Port Arthur refinery currently meets the 500 ppm specifications. We would thus
continue to have a market for our current diesel production at Port Arthur,
albeit a smaller and lower-priced market, and therefore we could elect not to
make any capital expenditures necessary to comply with the new on-road standard.
Depending upon the standard promulgated for off-road diesel, if any, and the
compliance strategy we adopt, the estimate or our capital expenditures in the
aggregate through 2006 required to comply with the diesel standards utilizing
existing technologies may range from $150 million to $200 million. More than 90%
of the projected investment is expected to be incurred during 2004 through 2006
with the greatest concentration of spending occurring in 2005.

     In addition, in September 1998, the Environmental Protection Agency
proposed regulations to implement MACT II, which regulates emissions of
hazardous air pollutants from certain refinery units. Finalization of the MACT
II regulations has been delayed in an attempt to harmonize the MACT II
requirements with Tier 2 gasoline and low-sulfur diesel requirements. If the
MACT II regulations are finalized and implemented as proposed, we expect to
spend approximately $60 million in the three years following their finalization
in order to comply with them. We expect the spending to be approximately evenly
divided in each of the three years.

Cash Flows from Financing Activities

     Cash flows used in financing activities for the nine months ended September
30, 2001 were $56.8 million as compared to $34.9 million for the same period
last year. In the third quarter of 2001, the Company repurchased in the open
market, $21.3 million at face value of its 9 1/2% Senior Notes for $20.3
million. The Company also returned capital of $25.0 million to Premcor USA that
allowed Premcor USA to repurchase a portion of its long-term debt and
exchangeable preferred stock in the open market and $0.8 million for interest
payments on the long-term debt. The nine months ended September 30, 2001 also
included a $9.6 million financing charge to extend the original expiration date
as well as amend and restate the working capital facility. The nine months ended
September 30, 2000 included a balloon payment on a capitalized lease at the
Hartford refinery and a return of capital to Premcor USA to be used for interest
payments on Premcor USA's long-term debt. We continue to evaluate the most
efficient use of capital and, from time to time, depending upon market
conditions, may seek to purchase certain of our outstanding debt securities in
the open market or by other means, in each case to the extent permitted by
existing covenant restrictions.

     Premcor USA, which owns all of our outstanding common stock, relies on us
for substantially all of its liquidity in order to meet its interest and other
costs. Premcor USA is required to make semi-annual interest payments on its 10
7/8% Notes due 2005 of $7.9 million on June 1 and December 1 of each year and
expects its other operating costs to total less than $1 million per year.
Premcor USA currently pays dividends on its 11 1/2% Exchangeable Preferred Stock
in kind. Premcor USA's ability to access our cash flows from operating
activities is limited by covenants governing certain of our outstanding debt
securities. Under the most restrictive covenants, we are able to return
additional capital of approximately $54 million to Premcor USA as of September
30, 2001. Cash, cash equivalents, and short-term investments owned by Premcor
USA amounted to $33.4 million at September 30, 2001.

     Funds generated from operating activities together with existing cash, cash
equivalents and short-term investments and proceeds from asset sales are
expected to be adequate to fund existing requirements for working capital and
capital expenditure programs for the next year. Due to the commodity nature of
our products, our operating results are subject to rapid and wide fluctuations.
While we believe that our maintenance of large cash, cash equivalents and
short-term investment balances and our operating philosophies will be sufficient
to provide us with adequate liquidity through the next year, there can be no
assurance that market conditions will

                                       31

<PAGE>

not be worse than anticipated. Future working capital, discretionary capital
expenditures, environmentally mandated spending and acquisitions may require
additional debt or equity capital.

New and Proposed Accounting Standards

     In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 1999, the FASB issued
SFAS No. 137 "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB Statement No. 133" which
delayed the effective date of SFAS No. 133 for one year to fiscal years
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138
"Accounting for Certain Derivative Instruments and Hedging Activities" which
amended various provisions of SFAS No. 133. We adopted SFAS No. 133, as amended,
effective January 1, 2001. The adoption of SFAS No. 133 did not have a material
impact on the Company's financial position or results of operations because we
have historically marked to market all financial instruments used in the
implementation of our hedging strategies.

     On July 20, 2001 the FASB issued SFAS No.141 "Business Combinations" and
SFAS No. 142 "Goodwill and Other Intangible Assets". SFAS No. 141, which became
effective on issuance,  requires business combinations initiated after June 30,
2001 to be accounted for using the purchase  method of accounting and addresses
the initial recording of intangible assets separate from goodwill. SFAS No. 142
requires that goodwill and intangible assets with indefinite  lives will not be
amortized,  but will be tested at least annually for impairment. Intangible
assets  with finite lives will continue to be amortized. SFAS No. 142 is
effective for fiscal years beginning after December 15, 2001. We do not expect
the implementation of these standards to have a material effect on our financial
position and results of operations.

     In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset
Retirement Obligations".  SFAS No. 143  addresses  when a  liability  should be
recorded for asset retirement obligations and how to measure this liability. The
initial recording of a liability for an asset retirement obligation will require
the recording of a corresponding  asset, which will be required to be amortized.
SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are
in the process of evaluating  the impact of the adoption of this standard on our
financial position and results of operations.

     The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants ("AICPA") has issued an exposure draft of a
proposed statement of position ("SOP") entitled "Accounting for Certain Costs
and Activities Related to Property, Plant and Equipment." If adopted as
proposed, this SOP would require companies to expense as incurred turnaround
costs, defined as "the non-capital portion of major maintenance costs." Adoption
of the proposed SOP would also require that any existing unamortized turnaround
costs be expensed immediately. A turnaround is a periodically required standard
procedure for maintenance of a refinery that involves the shutdown and
inspection of major processing units and generally occurs every three to five
years. Turnaround costs include actual direct and contract labor and material
costs for the overhaul, inspection, and replacement of major components of
refinery processing and support units performed during turnaround. Turnaround
costs, which are included in our consolidated balance sheet in "Other Assets,"
are currently amortized on a straight-line basis over the period until the next
scheduled turnaround, beginning

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<PAGE>

the month following completion. The amortization of turnaround costs is
presented as "Amortization" in our consolidated statements of operations.

     The proposed SOP requires adoption for fiscal years beginning after June
15, 2002. If this proposed change were in effect at September 30, 2001, we would
have been required to write-off unamortized turnaround costs of approximately
$101 million. Unamortized turnaround costs will change throughout the year as
maintenance turnarounds are performed and past maintenance turnarounds are
amortized. If adopted in its present form, charges related to this proposed
change would be taken in the first quarter of 2003 and would be reported as a
cumulative effect of an accounting change, net of tax, in the consolidated
statements of operations.

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<PAGE>

PART II. - OTHER INFORMATION

ITEM 1. - Legal Proceedings

     The following is an update of developments during the quarter of material
pending legal proceedings to which we or any of our subsidiaries are a party or
to which any of our or their property is subject, including environmental
proceedings that involve potential monetary sanctions of $100,000 or more and to
which a governmental authority is a party.

     Port Arthur: Natural Resource Damage Assessment. In 1999, Premcor USA Inc.
and Chevron received a notice from a number of federal and Texas agencies that a
study would be conducted to determine whether any natural resource damage
occurred as a result of the operation of the Port Arthur refinery prior to
January 1, 2000. The Company is cooperating with the government agencies in this
investigation. The Company entered into an agreement with Chevron pursuant to
which Chevron will indemnify the Company for the claim in consideration of a
payment of $750,000.

     Lima: Finding of Violation. On July 10, 2001, the Ohio Environmental
Protection Agency issued a finding of violation by the Company of state and
federal laws regarding releases of annual benzene quantities into refinery
wastewater streams in excess of that allowed and downtime of continuous emission
control monitors that exceeded the allowed 5%. The Company has settled this
action, paid a fine of $120,000 and implemented preventive programs to ensure
future compliance.

     As of September 30, 2001, we had accrued a total of $71 million, on an
undiscounted basis, for legal and environmental-related obligations that may
result from the matters noted above, other legal and environmental matters, and
obligations associated with certain retail sites we previously owned. We are of
the opinion that the ultimate resolution of these claims, to the extent not
previously provided for, will not have a material adverse effect on our
consolidated financial condition, results of operations, or liquidity. However,
an adverse outcome of any one or more of these matters could have a material
effect on quarterly or annual operating results or cash flows when resolved in a
future period.

     In addition to the specific matters discussed above, we also have been
named in various other suits and claims. While it is not possible to estimate
with certainty the ultimate legal and financial liability with respect to these
other legal proceedings, we believe the outcome of these other suits and claims
will not have a material adverse effect on our financial position, results of
operations, or liquidity.

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<PAGE>


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

(a)      Exhibits

      Exhibit
      Number                          Description
      -------                         -----------

       3.1         Restated Certificate of Incorporation of The Premcor
                   Refining Group Inc. (f/k/a Clark Refining & Marketing, Inc.
                   and Clark Oil & Refining Corporation) effective as of
                   February 1, 1993 (Incorporated by reference to Exhibit 3.1
                   filed with the Company's Annual Report on Form 10-K, for the
                   year ended December 31, 2000 (Commission File No. 1-11392))

       3.2         Certificate of Amendment to Certificate of Incorporation of
                   The Premcor Refining Group Inc. (f/k/a Clark Refining &
                   Marketing, Inc. and Clark Oil & Refining Corporation)
                   effective as of September 30, 1993 (Incorporated by
                   reference to Exhibit 3.2 filed with the Company's Annual
                   Report on Form 10-K, for the year ended December 31, 2000
                   (Commission File No. 1-11392))

       3.3         Certificate of Amendment of Restated Certificate of
                   Incorporation of The Premcor Refining Group Inc. (f/k/a
                   Clark Refining & Marketing, Inc. and Clark Oil & Refining
                   Corporation) effective as of May 9, 2000 (Incorporated by
                   reference to Exhibit 3.3 filed with the Company's Annual
                   Report on Form 10-K, for the year ended December 31, 2000
                   (Commission File No. 1-11392))

       3.4         By-laws of The Premcor Refining Group Inc. (f/k/a Clark
                   Refining & Marketing, Inc. and Clark Oil & Refining
                   Corporation) (Incorporated by reference to Exhibit 3.2 filed
                   with the Company's Registration Statement on Form  S-1
                   (Registration No. 33-28146))

       4.1         Indenture dated as of August 10, 1998 between The Premcor
                   Refining Group Inc. (f/k/a Clark Refining & Marketing, Inc.
                   and Clark Oil & Refining Corporation) and Bankers Trust
                   Company, as Trustee, including the form of the 8 5/8% Senior
                   Notes due 2008 (Incorporated by reference to Exhibit 4.1
                   filed with the Company's Form S-4 (Registration  No.
                   333-64387))

       4.2         Indenture between The Premcor Refining Group Inc. (f/k/a
                   Clark Refining & Marketing, Inc. and Clark Oil & Refining
                   Corporation) and NationsBank of Virginia, N.A. including the
                   form of 9 1/2% Senior Notes due 2004 (Incorporated by
                   reference to Exhibit 4.1 filed with the Company's
                   Registration Statement on Form S-1 (File No. 33-50748))

       4.3         Supplemental Indenture between The Premcor Refining Group
                   Inc. (f/k/a Clark Refining & Marketing, Inc. and Clark Oil &
                   Refining Corporation) and NationsBank of Virginia, N.A.,
                   dated  February 17, 1995 (Incorporated by reference to
                   Exhibit 4.6 filed with the Company's Annual Report on Form
                   10-K for the year ended December 31, 1994 (File  No.
                   33-59144))

                                     35

<PAGE>


      Exhibit
      Number                             Description
      -------                            -----------
        4.4         Indenture between The Premcor Refining Group Inc. (f/k/a
                    Clark Refining & Marketing, Inc. and Clark Oil & Refining
                    Corporation) and Bankers Trust Company, dated as of November
                    21, 1997, including the form of 8 3/8 Senior Notes due 2007
                    (Incorporated by reference to Exhibit 4.5 filed with the
                    Company's Registration Statement on Form S-4 (Registration
                    No. 333-42431))

        4.5         Indenture between The Premcor Refining Group Inc. (f/k/a
                    Clark Refining & Marketing, Inc. and Clark Oil & Refining
                    Corporation) and Marine Midland Bank, dated as of November
                    21, 1997, including the form of 8 7/8% Senior Subordinated
                    Notes due 2007 (Incorporated by reference to Exhibit 4.6
                    filed with the Company's Registration Statement on Form S-4
                    (Registration No. 333-42431))

        4.6         Supplemental Indenture between The Premcor Refining Group
                    Inc. (f/k/a Clark Refining & Marketing, Inc. and Clark Oil &
                    Refining Corporation) and Marine Midland Bank, dated as of
                    November 21, 1997 (Incorporated by reference to Exhibit 6.1
                    filed with the Company's Registration Statement on Form S-4
                    (Registration No. 333-42431))

       10.1         Amended and Restated Credit Agreement dated August 23,
                    2001, among The Premcor Refining Group, Deutsche Banc Alex.
                    Brown Inc, as Lead Arranger, Bankers Trust Company, as
                    Administrative and Collateral Agent, TD Securities (USA),
                    Inc., as Syndication Agent, Fleet National Bank, as
                    Documentation Agent, and the other financial institutions
                    party thereto (Incorporated by reference to Exhibit 10.1
                    filed with Premcor Inc.'s Registration Statement on Form S-1
                    (Registration No. 333-70314)).

         (b)    Reports on Form 8-K

                    Except as previously disclosed, the Company has not filed
                    any reports on Form 8-K during the period covered by this
                    report and up to and including the date of filing of this
                    report.




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<PAGE>

SIGNATURE

     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.

                                            THE PREMCOR REFINING GROUP INC.
                                                         (Registrant)




                                            /s/ Dennis R. Eichholz
                                            ------------------------------------
                                            Dennis R. Eichholz
                                            Controller (Principal
                                               Accounting Officer and
                                               Duly Authorized Officer)



November 13, 2001

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