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

FORM 10-K
(Mark One)

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

For the fiscal year ended December 31, 2001

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 333-92871-02

SABINE RIVER HOLDING CORP.
(Exact name of registrant as specified in its charter)

DELAWARE 43-1857408
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)

1801 S. GULFWAY DRIVE
OFFICE NO. 36
PORT ARTHUR, TEXAS 77640
(Address of principal executive offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (409) 982-7491

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

Number of shares of registrant's common stock, $.01 par value,
outstanding as of March 1, 2002: 6,818,182.

SABINE RIVER HOLDING CORP.

TABLE OF CONTENTS

PAGE

PART I
Item 1. Business...................................................................................................2
Item 2. Properties................................................................................................10
Item 3. Legal Proceedings.........................................................................................16
Item 4. Submission of Matters to a Vote of Security Holders.......................................................16

PART II
Item 5. Market for the Registrant's Common Stock and Related Shareholder Matters..................................17
Item 6. Selected Financial Data...................................................................................17
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.....................18
Item 7A. Quantitative and Qualitative Disclosures about Market Risk................................................29
Item 8. Financial Statements and Supplementary Data...............................................................30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................31

PART III
Item 10. Directors and Executive Officers of the Registrant.......................................................32
Item 11. Executive Compensation...................................................................................33
Item 12. Security Ownership of Certain Beneficial Owners and Management...........................................34
Item 13. Certain Relationships and Related Transactions...........................................................35

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..........................................38

Signatures

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. You can also identify the
forward looking statements by the fact that they do not relate strictly to
historical or current facts.

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 could cause actual results to differ
materially from our expectations as set forth in our forward-looking
statements. These factors include, but are not limited to, changes in:

o Industry-wide refining margins;

o Crude oil and other raw material costs, the cost of transportation of
crude oil, embargoes, industry expenditures for the discovery and
production of crude oil, military conflicts between, or internal
instability in, one or more oil-producing countries, governmental
actions, and other disruptions of our ability to obtain crude oil;

o Market volatility due to world and regional events;

o Availability and cost of debt and equity financing;

o Labor relations;

o U.S. and world economic conditions;

o Supply and demand for refined petroleum products;

o Reliability and efficiency of our operating facilities which are
affected by such potential hazards as equipment malfunctions, plant
construction/repair delays, explosions, fires, oil spills and the
impact of severe weather;

o Actions taken by competitors which may include both pricing and
expansion or retirement of refinery capacity;

o Civil, criminal, regulatory or administrative actions, claims or
proceedings and regulations dealing with protection of the
environment, including refined petroleum product specifications and
characteristics; and

o Other unpredictable or unknown factors not discussed, including acts
of war or terrorism.

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

PART I

ITEM 1. BUSINESS

As used in this Form 10-K, the terms "we," "our," or "us" refer to
Sabine River Holding Corp. and its consolidated subsidiaries, taken as a
whole, unless the context otherwise indicates. Sabine River Holding Corp.
should be distinguished from Premcor USA Inc. and The Premcor Refining Group
Inc., or PRG, which are companies affiliated with us that also file Forms 10-K
with the Securities and Exchange Commission. Sabine River Holding Corp. files
Form 10-K and other periodic reports with the Securities and Exchange Commission
on behalf of its subsidiary, Port Arthur Finance Corp., due to the full and
unconditional guarantee by Sabine River Holding Corp. of certain debt securities
issued by Port Arthur Finance Corp.

OVERVIEW AND RECENT DEVELOPMENTS

We own and operate, via our wholly-owned operating subsidiary, Port
Arthur Coker Company L.P., or PACC, a heavy oil processing facility that
includes a new 80,000 barrels per day, or bpd, delayed coking unit, a 35,000 bpd
hydrocracker unit, and a 417 long tons per day sulfur complex. We operate our
facility in conjunction with the refining assets of our affiliate, PRG, at its
Port Arthur, Texas refinery. Our heavy oil processing facility, along with
modifications made by PRG at its Port Arthur refinery, allows the refinery to
process primarily lower-cost, heavy sour crude oil.

We were formed as part of a project designed to increase the Port
Arthur refinery's capability of processing heavy sour crude oil from 20% to
80%, referred to hereinafter as the heavy oil upgrade project. Our role in the
project was to develop, finance and construct our heavy oil processing facility
at the Port Arthur refinery. PRG's role in the project was to expand its crude
oil throughput capacity to 250,000 bpd and to make certain other improvements to
its existing facilities at its Port Arthur refinery. The heavy oil upgrade
project, including our heavy oil processing facility, achieved substantial
mechanical completion by the end of 2000 and began operating at full design
capacity during the second quarter of 2001. Substantial reliability, as defined
in our financing documents and construction contracts, of the heavy oil upgrade
project was achieved as of September 30, 2001, and final completion was achieved
as of December 28, 2001.

The Port Arthur refinery, which is owned by PRG, is located on the
Gulf Coast. The refinery includes, in addition to our operating units, a 250,000
bpd crude unit, a catalytic reformer, a fluid catalytic cracking unit, and a
hydrofluoric acid alkylation unit. Since acquiring the refinery in 1995, PRG has
increased the crude oil throughput capacity from approximately 178,000 bpd to
its current 250,000 bpd and expanded the refinery's ability to process heavy
sour crude oil.

Currently, our business operations and PRG's business operations are
interdependent and governed by certain intercompany and other agreements. We
sell the refined and intermediate products produced by our heavy oil processing
facility to PRG (which it then further processes and sells to third parties). We
lease the crude unit, certain other equipment and the site on which our heavy
oil processing units are located from PRG. In addition, PRG provides us with
certain services and supplies necessary to operate our heavy oil processing
facility. For a discussion of the agreements underlying our relationship with
PRG and other third parties, see "--Summary of Principal Contracts."

We were incorporated in Delaware in May of 1999 and were capitalized
in August of 1999. We are the 1% general partner of PACC and the 100% owner of
Neches River Holding Corp., which is the 99% limited partner of PACC. We are
owned 90% by Premcor Inc. and 10% by Occidental Petroleum Corporation, or
Occidental. Premcor Inc. is principally owned by Blackstone Capital Partners
III Merchant Banking Fund L.P. and its affiliates, or Blackstone, with a current
voting interest of 80.2% and by Occidental with an 18.4% current voting
interest.

On February 1, 2002, Thomas D. O'Malley was elected our chairman,
president, chief executive officer and chief operating officer. Mr. O'Malley
was formerly vice chairman of Phillips Petroleum Corporation, and prior to
that chairman and chief executive officer of Tosco Corporation. Mr. O'Malley
has assembled an executive management team consisting of William E. Hantke,
our new executive vice president and chief financial officer, and Jeffry N.
Quinn, our executive vice president and general counsel. Mr. Hantke was
formerly a member of the senior management team at Tosco Corporation prior to
its merger with Phillips Petroleum Corporation. Mr. Quinn joined us in 2000
and was formerly a member of the executive management team at Arch Coal, Inc.

SUMMARY OF PRINCIPAL CONTRACTS

Each of our principal operating agreements, including our
intercompany agreements with PRG, is discussed below. Our wholly-owned
subsidiary, PACC, is the actual party to most of these agreements.

Construction Contract

In July 1999, we entered into a contract with Foster Wheeler for the
engineering, procurement and construction of the heavy oil processing
facility. Under this construction contract, Foster Wheeler agreed to engineer,
design, procure equipment for, construct, test, and oversee start-up of the
heavy oil processing facility and to integrate the heavy oil processing facility
with the Port Arthur refinery. We agreed to pay Foster Wheeler a fixed price of
approximately $544 million, of which $157.1 million was credited to us for
amounts PRG had already paid Foster Wheeler for work performed on the heavy oil
processing facility prior to August 1999. We purchased this work in progress for
fair market value from PRG when the financings for the construction were
consummated in August 1999. Construction of the heavy oil processing facility
and the entire heavy oil upgrade project achieved substantial mechanical
completion by the end of 2000 and the project as a whole began operating at full
design capacity during the second quarter of 2001. Substantial reliability, as
defined in our financing documents and construction contracts, of the heavy oil
upgrade project was achieved as of September 30, 2001, and final completion was
achieved as of December 28, 2001.

Crude Oil Supply Agreement

In August 1999, we purchased from PRG a long-term crude oil supply
agreement with P.M.I. Comercio International, S.A. de C.V., an affiliate of
PEMEX, the Mexican state oil company, for approximately $0.8 million. Under the
terms of this agreement, we are obligated to buy Maya crude oil from the PEMEX
affiliate, and the PEMEX affiliate is obligated to sell to us Maya crude oil.
The long-term crude oil supply agreement includes a price adjustment mechanism
designed to minimize the effect of adverse refining margin cycles and to
moderate the fluctuations of the coker gross margin, a benchmark measure of the
value of coker production over the cost of coker feedstock. This price
adjustment mechanism contains a formula that represents an approximation for the
coker gross margin and provides for a minimum average coker gross margin of $15
per barrel over the first eight years of the agreement, which began on April 1,
2001. The agreement expires in 2011.

On a monthly basis, the actual coker gross margin is calculated and
compared to the minimum. Coker gross margins exceeding the minimum are
considered a "surplus" while coker gross margins that fall short of the minimum
are considered a "shortfall." On a quarterly basis, the surplus and shortfall
determinations since the beginning of the contract are aggregated. Pricing
adjustments to the crude oil we purchase are only made when there exists a
cumulative shortfall. When this quarterly aggregation first reveals that a
cumulative shortfall exists, we receive a discount on our crude oil purchases in
the next quarter in the amount of the cumulative shortfall. If thereafter, the
cumulative shortfall incrementally increases, we receive additional discounts on
our crude oil purchases in the succeeding quarter equal to the incremental
increase, and conversely, if thereafter, the cumulative shortfall incrementally
decreases, we repay discounts previously received, or a premium, on our crude
oil purchases in the succeeding quarter equal to the incremental decrease. Cash
crude oil discounts received by us in any one quarter are limited to $30
million, while our repayment of previous crude oil discounts, or premiums, are
limited to $20 million in any one quarter. Any amounts subject to the quarterly
payment limitations are carried forward and applied in subsequent quarters.

As of December 31, 2001, as a result of the favorable market
conditions related to the value of Maya crude oil versus the refined products
derived from it, a cumulative quarterly surplus of $110.0 million existed under
the contract. As a result, to the extent we experience quarterly shortfalls in
coker gross margins going forward, the price we pay for Maya crude oil in
succeeding quarters will not be discounted until this cumulative surplus is
offset by future shortfalls.

Ancillary Equipment Lease

Pursuant to an ancillary equipment lease, we pay a lease fee to
PRG for use of 100% of its crude/vacuum unit and distillate, kerosene and
naphtha hydrotreaters. In addition, under the ancillary equipment lease, we pay
operating fees for these units, which include turnaround, capital expenditures,
fuel, and fixed operating costs. Other costs include certain utilities and
environmental services, such as the provision of nitrogen, demineralized water
and other services. We are obligated to pay PRG quarterly lease payments of
approximately $8 million, adjusted for inflation, through the lease term. The
quarterly lease fee is based on a capital recovery charge for both existing
asset values and cost associated with the upgrade of the heavy oil upgrade
project. The initial term of the ancillary equipment lease is 30 years. We may
renew the lease for five additional five-year terms, at a rent based on a fair
market rental value agreed by us and PRG, or a value determined according to an
appraisal procedure specified in the lease agreement.

Services and Supply Agreement

We have entered into a services and supply agreement with PRG pursuant
to which PRG provides us with services necessary to operate the heavy oil
processing facility, including among others, the following:

o operation and maintenance of the ancillary units and equipment that
we lease from PRG;

o management of the operation and maintenance of the new processing
units and other equipment at the Port Arthur refinery;

o management of our crude oil purchases and transportation of our crude
oil to the Port Arthur refinery; and

o a supply of other required feedstocks, materials and utilities.

In addition, under our services and supply agreement, PRG has a right
of first refusal to use a portion of the processing capability of our new units
and the units we lease from PRG. In exchange, we receive processing fees from
PRG.

Product Purchase Agreement

We have entered into a product purchase agreement with PRG for the sale
of all intermediate and finished refined products produced by our heavy oil
processing facility. Under the agreement, PRG is obligated to accept and pay for
all of the products we produce and has a limited right to request that we
produce a specified mix of products. We began selling products to PRG under this
agreement in November 2000.

Ground Lease

In August 1999, we entered into a ground lease with PRG pursuant to
which we lease the sites within the Port Arthur refinery on which our new
processing units are located. The initial term of the ground lease is 30 years.
We may renew the ground lease for five additional five-year terms. PRG granted
us a nonexclusive easement over and under the remaining Port Arthur refinery
property as necessary to own, construct and operate our heavy oil processing
facility and maintain and operate the units leased to us.

Hydrogen Supply Agreement

We have entered into a hydrogen supply agreement with Air Products
and Chemicals, Inc., or Air Products, pursuant to which Air Products supplies
the hydrogen requirements of our heavy oil processing facility. Under this
agreement, Air Products was obligated to design and construct a new hydrogen
supply plant at the Port Arthur refinery according to agreed-upon milestones and
specifications. Once the hydrogen plant was installed and ready for commercial
operation in November 2000, Air Products began supplying the hydrogen
requirements of our heavy oil processing facility as required under this
agreement. The term of this agreement is to continue for 246 consecutive months
after startup. Thereafter, the hydrogen supply agreement renews annually unless
terminated in accordance with the agreement. Air Products is obligated to supply
and we are obligated to purchase all of the hydrogen we use at the Port Arthur
refinery up to a maximum quantity of 80 million standard cubic feet per day.

Marine Dock and Terminaling Agreement

PRG and Sun Pipe Line Company entered into a marine dock and
terminaling agreement in August 1999 under which Sun Pipe Line delivers crude
oil from its Nederland, Texas dock terminal facility to PRG's pipeline located
on Sun Pipe Line's property. This agreement also provides for the delivery of
some of our crude oil. In October 2000, we amended the agreement to provide for
a month-to-month term and to eliminate minimum volume requirements.

In January 2000, we entered into a terminal services agreement with
Oiltanking Houston, Inc., or Oiltanking, under which Oiltanking is required to
transport at least 18.25 million barrels per year of crude oil from its
Beaumont, Texas terminal to the Lucas terminal tank farm owned by PRG. The
agreement became effective on October 1, 2000 for a term of nine years, and
renews annually thereafter unless terminated by either party upon six months
notice.

Sanko Steamship Agreement

In May 2001, we entered into marine charter agreements with The Sanko
Steamship Co., Ltd. of Tokyo, Japan, for three tankers custom designed for
delivery to our docks. We intend to use the ships solely to transport Maya crude
oil from the loading port in Mexico to the refinery dock in Port Arthur. Because
of the custom design of the tankers, the dock will be accessible 24 hours a day
by the tankers, unlike the daylight-only transit requirement applicable to ships
approaching other terminals in the Port Arthur area. In addition, the size of
the custom tankers will allow our crude oil requirements to be satisfied with
fewer delivery trips to the dock. We believe our marine charter arrangement will
improve delivery reliability of crude oil to the Port Arthur refinery and will
save approximately $10 million per year due to reduced third party terminal
costs and the benefit of fewer trips. The ships are currently under construction
and are scheduled for delivery in late 2002. The charter agreements have an
eight-year term from the date of delivery of each ship and are renewable for two
one-year periods.

OPERATIONS

Our heavy oil processing facility began operating at full design
capacity in the second quarter of 2001. The facility is designed to allow us
to process an average of approximately 250,000 bpd of crude oil.

Feedstocks and refined products produced at the Port Arthur facility
are principally commodities and the pricing of such feedstocks and refined
products under the services and supply agreement and product purchase
agreement is intended to reflect market prices. As a result, our operating
cash flows and earnings are significantly affected by a variety of 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 economic conditions, weather patterns, political
affairs, crude oil production levels, planned and unplanned downtime in
refineries, the rate of industry investments, the availability of imports, the
marketing of competitive fuels and the extent of government regulation. In
addition, seasonal fluctuations generally result in stronger operating cash
flows and earnings during the higher transportation-demand periods of spring
and summer and weaker operating cash flows and earnings during the fall and
winter.

FEEDSTOCKS AND PRODUCTION

FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
2000 (a) 2001
---------------------------- -----------------------------
BPD PERCENT BPD PERCENT OF
(THOUSANDS) OF TOTAL (THOUSANDS) TOTAL
------------- ----------- ------------- --------------

FEEDSTOCKS
CRUDE OIL THROUGHPUT:
Medium sour crude oil.............. 3.6 40.4% 38.0 20.4%
Heavy sour crude oil............... 5.3 59.6 148.0 79.6
------------- ----------- ------------- --------------
TOTAL CRUDE OIL.................. 8.9 100.0% 186.0 100.0%
============= =========== ============= ==============

PRODUCTION
Intermediate throughput produced for The
Premcor Refining Group............. 8.8 87.1 180.0 91.0
Petroleum coke and sulfur............. 1.0 9.9 17.7 8.9
Residual oil.......................... 0.3 3.0 0.1 0.1
------------- ----------- ------------- --------------
TOTAL PRODUCTION................. 10.1 100.0% 197.8 100.0%
============= =========== ============= ==============

(a) Operations of our heavy oil processing facility commenced in early
December of 2000.

PRODUCTS AND CRUDE OIL SUPPLY

All of our refined products are sold to PRG pursuant to the product
purchase agreement. Thus, the product purchase agreement is our sole source of
revenue from the sale of refined products. However, because we are located in a
highly liquid refined products market our intermediate and finished refined
products would be readily marketable to third parties at the same or somewhat
discounted prices in the event PRG failed to meet its purchase obligations under
the contract.

We have no crude oil reserves and are not engaged in exploration or
production activities. We obtain our crude oil requirements pursuant to the
long-term crude oil supply agreement with the affiliate of PEMEX, on the spot
market from unaffiliated sources or from PRG pursuant to the services and supply
agreement. We believe that we will be able to obtain adequate crude oil and
other feedstocks at generally competitive prices in the foreseeable future.

The following table shows our average daily sources of crude oil for
the year ended December 31, 2001:

YEAR ENDED DECEMBER 31, 2001
----------------------------------------
BPD PERCENT OF
SOURCES OF CRUDE OIL SUPPLY (THOUSANDS) TOTAL
-------------------- ----------------

Mexico.................................... 152.5 81.2%
Middle East............................... 35.3 18.8
-------- --------
TOTAL..................................... 187.8 100.0%
======== ========

COMPETITION

The refining industry is highly competitive. We expect our operating
cash flows and earnings to be affected by the competitive position of the Port
Arthur refinery. Many of the Port Arthur refinery's principal competitors, of
which there are 28 other refineries located on the U.S. Gulf Coast, are owned
by integrated multinational oil companies that are substantially larger than
us and our affiliates. Because of their geographic diversity, integration of
operations, larger capitalization and greater resources, these major oil
companies may be better able to withstand volatile market conditions, more
effectively compete on the basis of price and more readily obtain crude oil in
times of shortage.

Our industry is subject to extensive environmental regulations,
including new standards governing sulfur content in gasoline and diesel fuel.
These regulations will have a significant impact on the refining industry and
will require substantial capital outlays by us and our competitors in order to
upgrade our facilities to comply with the new standards. For further information
on environmental compliance, see "--Environmental Compliance." Competitors who
have more modern plants than we do may not spend as much to comply with the
regulations and may be better able to afford the upgrade costs.

ENVIRONMENTAL MATTERS

We are subject to extensive federal, state and local laws and
regulations relating to the protection of the environment. These laws and the
accompanying regulatory programs and enforcement initiatives, some of which
are described below, impact our business and operations by imposing:

o restrictions or permit requirements on our ongoing operations;

o liability in certain cases for the remediation of contaminated
soil and groundwater at our current or former facilities and at
facilities where we have disposed of hazardous materials; and

o specifications on the petroleum products we produce.

The laws and regulations we are subject to often change and may
become more stringent. The ultimate impact of complying with existing laws and
regulations is not always clearly known or determinable due in part to the
fact that operations may change over time and certain implementing regulations
for laws such as the Resource Conservation and Recovery Act and the Clean Air
Act have not yet been finalized, are under governmental or judicial review or
are being revised. These regulations and other new air and water quality
standards and stricter fuel regulations could result in increased capital,
operating and compliance costs. For further discussion of these laws and
regulations and their impact on our cash flow, see "--Environmental
Compliance", "Risks Related to our Business and our Industry--Compliance with,
and changes in, environmental laws could adversely affect our results of
operations and our financial condition" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources--Cash Flows from Investing Activities."

ENVIRONMENTAL COMPLIANCE

The principal environmental risks associated with our operations are
air emissions, releases into soil and groundwater and wastewater excursions.
The primary legislative and regulatory programs that affect these areas are
outlined below.

The Clean Air Act

The Clean Air Act and the corresponding state laws that regulate
emissions of materials into the air affect refining operations both directly
and indirectly. Direct impacts on refining operations may occur through Clean
Air Act permitting requirements and/or emission control requirements relating
to specific air pollutants. For example, fugitive dust, including fine
particulate matter measuring ten micrometers in diameter or smaller, may be
subject to future regulation. The Clean Air Act indirectly affects refining
operations by extensively regulating the air emissions of sulfur dioxide and
other compounds, including nitrogen oxides, emitted by automobiles, utility
plants and other sources, which are direct or indirect users of our products.

The Clean Air Act imposes stringent limits on air emissions,
establishes a federally mandated operating permit program and allows for civil
and criminal enforcement sanctions. The Clean Air Act also establishes
attainment deadlines and control requirements based on the severity of air
pollution in a geographical area. Our heavy oil processing facility operates
under air permits maintained by us.

In July 1997, the United States Environmental Protection Agency, or the
EPA, promulgated more stringent National Ambient Air Quality Standards for
ground-level ozone and fine particulate matter. In May 1999, a federal appeals
court overturned the new standards. In February 2001, the United States Supreme
Court affirmed in part, reversed in part, and remanded the case to the EPA to
develop a reasonable interpretation of the nonattainment implementation
provisions insofar as they relate to the revised ozone standards. Additionally,
in 1998, the EPA published a final rule addressing the regional transport of
ground-level ozone across state boundaries to the eastern United States through
nitrogen oxide emissions reduction from various emissions sources, including
refineries. The rule requires nineteen states and the District of Columbia to
revise their state implementation plans to reduce nitrogen oxide emissions. In a
related action in December 1999, the EPA granted a petition from several
Northeastern states seeking the adoption of stricter nitrogen oxide standards by
Midwestern states. The impact of the revised ozone and nitrogen oxide standards
could be significant to us, but the potential financial effects cannot be
reasonably estimated until the EPA takes further action on the revised ozone
National Ambient Air Quality Standards, or any further judicial review occurs,
and the states, as necessary, develop and implement revised state implementation
plans in response to the revised ozone and nitrogen oxide standards.

The Clean Water Act

The federal Clean Water Act of 1972 affects refining operations by
imposing restrictions on effluent discharge into, or impacting, navigable water.
Regular monitoring, reporting requirements and performance standards are
preconditions for the issuance and renewal of permits governing the discharge of
pollutants into water. Our wastewater is treated and discharged pursuant to
agreements with PRG. In addition, we are regulated under the Oil Pollution Act,
which amended the Clean Water Act. Among other requirements, the Oil Pollution
Act requires the owner or operator of a tank vessel or a facility to maintain an
emergency oil response plan to respond to releases of oil or hazardous
substances. We have developed and implemented such a plan for our heavy oil
processing facility, which is covered by the Oil Pollution Act. Also, in case of
such releases, the Oil Pollution Act requires responsible companies to pay
resulting removal costs and damages, provides for substantial civil penalties,
and imposes criminal sanctions for violations of this law. The State of Texas,
in which we operate, has passed laws similar to the Oil Pollution Act.

Resource Conservation and Recovery Act

Our refining operations are subject to Resource Conservation and
Recovery Act requirements for the treatment, storage and disposal of hazardous
wastes. When feasible, Resource Conservation and Recovery Act materials are
recycled through coking operations instead of being disposed of on-site or
off-site. The Resource Conservation and Recovery Act establishes standards for
the management of solid and hazardous wastes. Besides governing current waste
disposal practices, the Resource Conservation and Recovery Act also addresses
the environmental effects of certain past waste disposal operations, the
recycling of wastes and the regulation of underground storage tanks containing
regulated substances. In addition, new laws are being enacted and regulations
are being adopted by various regulatory agencies on a continuing basis, and
the costs of compliance with these new rules can only be broadly appraised
until their implementation becomes more precisely defined.

Fuel Regulations

Tier 2 Motor Vehicle Emission Standards. In February 2000, the 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 parts per million, or 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 the Port Arthur refinery, including our heavy
oil processing facility, as a result of the Tier 2 standards. Based on our
current estimates, we believe that compliance with the new Tier 2 gasoline
specifications will require capital expenditures in the aggregate through 2005
of approximately one million dollars for our facility.

of the on-road diesel rule beyond 2006. The EPA has 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, 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. We estimate our capital
expenditures in the aggregate through 2006 required to comply with the diesel
standards at our heavy oil processing facility, utilizing existing technologies
is approximately $110 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. We intend to coordinate the investment to comply
with these new specifications with a potential joint project with PRG to expand
the crude oil throughput capacity of the Port Arthur refinery to 300,000 bpd. We
believe this project, combined with the low sulfur gasoline and diesel fuel
investments, will offer a reasonable return on capital.

Permitting

Refining companies must obtain numerous permits that impose strict
regulations on various environmental and safety matters in connection with oil
refining. Once a permit application is prepared and submitted to the
regulatory agency, it is subject to a completeness review, technical review
and public notice and comment period before it can be approved. Depending on
the size and complexity of the refining operation, some refining permits can
take considerable time to prepare and often take six months to two years or more
to receive approval. Regulatory authorities have considerable discretion in the
timing of the permit issuance and the public has rights to comment on and
otherwise engage in the permitting process, including through intervention in
the courts. We are not aware of any issues relating to our current permits or
any pending permit applications of our company or any of our subsidiaries.

ENVIRONMENTAL REMEDIATION

Under the Comprehensive Environmental Response, Compensation and
Liability Act, or CERCLA, and the Resource Conservation and Recovery Act and
similar state laws, certain persons may be liable for the release or
threatened release of hazardous substances including petroleum and its
derivatives into the environment. These persons include the current owner or
operator of property where the release or threatened release occurred, any
persons who owned or operated the property when the release occurred, and any
persons who arranged for the disposal of hazardous substances at the property.
Liability under CERCLA is strict, retroactive and, in most cases involving the
government as plaintiff, is joint and several, so that any responsible party
may be liable for the entire cost of investigating and remediating the release
of hazardous substances. As a practical matter, however, liability at most
CERCLA and similar sites is shared among all solvent potentially responsible
parties. The liability of a party is usually determined by the cost of
investigation and remediation, the portion of the hazardous substance(s) the
party contributed to the site, and the number of solvent potentially
responsible parties.

The release or discharge of crude oil, petroleum products or
hazardous materials can occur at our facility. In addition, the Port Arthur
refinery, including our heavy oil processing facility, has areas on-site that
may contain hazardous waste or hazardous substance contamination that may need
to be addressed in the future at substantial cost.

Environmental laws typically provide that the owners or operators,
including lessees, of contaminated properties may be held liable for their
remediation. Such liability is typically joint and several, which means that any
responsible party can be held liable for all remedial costs, and can be imposed
regardless of whether the owner or operator caused the contamination. We lease
the property on which our facility is located from PRG. Upon entering into that
lease in 1999, we evaluated the cost associated with remediation of the
groundwater and soil of that property and estimated remedial costs related to
the heavy oil processing facility at $1.6 million. PRG has agreed to retain
liability regarding that existing contamination and has indemnified us against
such liability. However, if PRG breaches its remediation obligations or if
significant liabilities arise with respect to future contamination, we could
incur substantial costs in remediating the contamination, which could impair our
financial condition or results of operations.

We believe that the remediation costs relating to contamination at
the heavy oil processing facility will be deferred until the final
decommissioning of the heavy oil processing units. However, actual remediation
costs, as well as the timing of such costs, are dependent on a number of
factors over which neither we nor PRG has control, including changes in
applicable laws and regulations, priorities of regulatory officials, interest
from local citizens groups, and development of new remediation methods. For
further discussion of risks related to environmental remediation, see "Risks
Related to our Business and our Industry--Environmental cleanup and remediaton
costs of our site and associated litigation could decrease our net cash flow,
reduce our results of operations and impair our financial condition."

ENVIRONMENTAL OUTLOOK

We have incurred, and will continue to incur, substantial capital,
operating and maintenance expenditures as a result of environmental laws and
regulations. To the extent these expenditures are not ultimately reflected in
the prices of the products we offer, our operating results will be adversely
affected. We believe that substantially all of our competitors are subject to
similar environmental laws and regulations. However, the specific impact on
each competitor may vary depending on a number of factors, including the age
and location of its operating facilities, marketing areas, production
processes and whether or not it is engaged in the petrochemical business or
the marine transportation of crude oil or refined products.

SAFETY AND HEALTH MATTERS

We are committed to achieving excellent safety and health
performance. We measure our success in this area primarily through the use of
accident frequency rates administrated by the Occupational Safety and Health
Administration. We believe that a superior safety record is inherently tied to
profitability and to achieving our productivity and financial goals. We seek
to implement this goal by:

o training employees in safe work practices;

o encouraging an atmosphere of open communication;

o involving employees in establishing safety standards; and

o recording, reporting and investigating all accidents to avoid
reoccurrence.

EMPLOYEES

As of December 31, 2001, our subsidiary, PACC, employed 51 employees.
Approximately 90% of those employees are covered by the same collective
bargaining agreement as the employees of PRG. That agreement expires in January
2006. Neither we, nor any of our other subsidiaries, have any employees.

ITEM 2. PROPERTIES

Our corporate office space is leased from PRG at 1801 S. Gulfway Drive,
Office No. 36, Port Arthur, Texas 77640. Our operating assets, which consist of
a new delayed coker unit, a hydrocracker unit, and a sulfur recovery complex,
are located on a subdivided site totaling less than 50 acres within the Port
Arthur refinery. We have entered into a 30-year fully-prepaid ground lease with
PRG for the site. Pursuant to the ground lease, PRG has also granted us an
easement over the remainder of the Port Arthur refinery and the right to use
certain other facilities and equipment at the refinery. For further information
regarding the ground lease between us and PRG, see "Business--Summary of
Principal Contracts--Ground Lease."

We also lease PRG's crude unit, vacuum tower and one naphtha and two
distillate hydrotreaters and the site on which they are located at the Port
Arthur refinery. Pursuant to the lease agreement, PRG has also granted us an
easement across the remainder of the Port Arthur refinery property, a portion of
PRG's dock adjacent to the Port Arthur refinery and specified pipelines and
crude oil handling facilities needed to transport crude oil from certain docking
facilities in Nederland, Texas to the Port Arthur refinery. For further
information regarding the facility and site lease between us and PRG, see
"Summary of Principal Contracts--Ancillary Equipment Lease".

RISKS RELATED TO OUR BUSINESS AND OUR INDUSTRY

VOLATILE MARGINS IN THE REFINING INDUSTRY MAY NEGATIVELY AFFECT OUR FUTURE
OPERATING RESULTS AND DECREASE OUR CASH FLOW.

Our financial results are primarily affected by the relationship, or
margin, between intermediate and refined product prices and the prices for crude
oil. The cost to acquire feedstocks and the price at which we can ultimately
sell intermediate and refined products depend upon a variety of factors beyond
our control. Historically, refining margins have been volatile, and they are
likely to continue to be volatile in the future. Future volatility may
negatively affect our results of operations, since the margin between refined
product prices and feedstock prices may decrease below the amount needed for us
to generate net cash flow sufficient for our needs.

Specific factors, in no particular order, that may affect our
refining margins include:

o accidents, interruptions in transportation, inclement weather or
other events that cause unscheduled shutdowns or otherwise
adversely affect our plants, machinery, pipelines or equipment,
or those of our suppliers or customers;

o changes in the cost or availability to us of transportation for
feedstocks and refined products;

o changes in fuel specifications required by environmental and
other laws, particularly with respect to oxygenates and sulfur
content;

o failure to successfully implement our planned capital projects
or to realize the benefits expected for those projects;

o rulings, judgments or settlements in litigation or other legal
matters, including unexpected environmental remediation or
compliance costs at our facilities in excess of any reserves,
and claims of product liability; and

o aggregate refinery capacity in our industry to convert heavy
sour crude oil into refined products.

Other factors that may affect our margins, as well as the margins in
the industry in general, include, in no particular order:

o domestic and worldwide refinery overcapacity or undercapacity;

o aggregate demand for crude oil and refined products, which is
influenced by factors such as weather patterns, including
seasonal fluctuations, and demand for specific products such as
jet fuel, which may themselves be influenced by acts of God,
nature and acts of terrorism;

o domestic and foreign supplies of crude oil and other feedstocks
and domestic supply of refined products, including from imports;

o the ability of the members of the Organization of Petroleum
Exporting Countries, or OPEC, to maintain oil price and
production controls;

o political conditions in oil producing regions, including the
Middle East, Africa and Latin America;

o refining industry utilization rates;

o pricing and other actions taken by competitors that impact the
market;

o price, availability and acceptance of alternative fuels;

o adoption of or modifications to federal, state or foreign
environmental, taxation and other laws and regulations;

o general economic conditions; and

o price fluctuations in natural gas.

A SIGNIFICANT INTERRUPTION OR CASUALTY LOSS AT THE PORT ARTHUR REFINERY COULD
REDUCE OUR PRODUCTION AND REDUCE OUR PROFITABILITY, PARTICULARLY IF NOT FULLY
COVERED BY INSURANCE.

Our operations could be subject to significant interruption if the
Port Arthur refinery were to experience a major accident, be damaged by severe
weather or other natural disaster, or otherwise be forced to shut down. Any
such shutdown would reduce production. For example, in May 2001 a lightning
strike at Port Arthur forced us to reduce throughput at the crude unit by
approximately 20,000 bpd and resulted in a ten-day shutdown of the crude unit
for repair in July 2001. There is also risk of mechanical failure and equipment
shutdowns. Furthermore, if any of the above events were not fully covered by our
insurance, it could have a material adverse effect on our earnings, other
results of operations and our financial condition.

DISRUPTION OF OUR ABILITY TO OBTAIN CRUDE OIL COULD REDUCE OUR MARGINS AND OUR
OTHER RESULTS OF OPERATIONS.

We have a long-term crude oil supply contract, and the remainder of
our crude oil supply is acquired on the spot market from unaffiliated sources or
from PRG pursuant to a services and supply agreement. Further, our feedstock
requirements are supplied from the Middle East and Mexico, and we are subject to
the political, geographic and economic risks attendant to doing business with
suppliers located in those regions. In the event that our long-term supply
contract was terminated, we may not be able to find alternative sources of
supply. If we are unable to obtain adequate crude oil volumes or are only able
to obtain such volumes at unfavorable prices, our margins and our other results
of operations could be materially adversely affected.

WE ARE HIGHLY DEPENDENT UPON ONE OF PEMEX'S AFFILIATES FOR ITS SUPPLY OF HEAVY
SOUR CRUDE OIL, WHICH COULD BE INTERRUPTED BY EVENTS BEYOND THE CONTROL OF
PEMEX.

Currently, we source approximately 80% of our crude oil from P.M.I.
Comercio Internacional, S.A. de C.V., or P.M.I, an affiliate of PEMEX, the
Mexican state oil company, under a long-term supply agreement that expires in
2011. Therefore, a large proportion of our crude oil needs is influenced by the
adequacy of PEMEX's crude oil reserves, the estimates of which are not precise
and are subject to revision at any time. In the event that PEMEX's affiliate
were to terminate our crude oil supply agreement or default on its supply
obligations, we would need to obtain heavy sour crude oil from another supplier
and would lose the potential benefits of the coker gross margin support
mechanism contained in the supply agreement. Alternative supplies of crude oil
may not be available or may not be on terms as favorable as those negotiated
with PEMEX's affiliate. In addition, the processing of crude oil supplied by a
third party may require changes to the configuration of the Port Arthur
refinery, which could require significant unbudgeted capital expenditures.

Furthermore, the obligation of PEMEX's affiliate to deliver heavy
sour crude oil under the agreement may be delayed or excused by the occurrence
of conditions and events beyond the reasonable control of PEMEX, such as:

o extreme weather-related conditions;

o production or operational difficulties and blockades;

o embargoes or interruptions, declines or shortages of supply
available for export from Mexico, including shortages due to
increased domestic demand and other national or international
political events; and

o certain laws, changes in laws, decrees, directives or actions of
the government of Mexico.

The government of Mexico may direct a reduction in our supply of crude oil, so
long as that action is taken in common with proportionately equal supply
reductions under its long-term crude oil supply agreements with other parties
and the amount by which it reduces the quantity of crude oil to be sold to us
shall first be applied to reduce quantities of crude oil scheduled for sale
and delivery to the Port Arthur refinery under any other crude oil supply
agreement with us or any of our affiliates. Mexico is not a member of OPEC,
but in 1998 it agreed with the governments of Saudi Arabia and Venezuela to
reduce Mexico's exports of crude oil by 200,000 bpd. In March 1999, Mexico
further agreed to cut exports of crude oil by an additional 125,000 bpd. As a
consequence, during 1999, PEMEX reduced its supply of oil under some oil
supply contracts by invoking an excuse clause based on governmental action
similar to one contained in our long-term crude oil supply agreement. It is
possible that PEMEX could reduce our supply of crude oil by similarly invoking
the excuse provisions in the future.

COMPETITORS WHO PRODUCE THEIR OWN SUPPLY OF FEEDSTOCKS, MAKE ALTERNATIVE FUELS
OR HAVE GREATER FINANCIAL RESOURCES THAN US MAY HAVE A COMPETITIVE ADVANTAGE.

The refining industry is highly competitive with respect to both
feedstock supply and refined product markets. We compete with numerous other
companies for available supplies of crude oil and other feedstocks. We are not
engaged in the petroleum exploration and production business and therefore do
not produce any of our crude oil feedstocks. Many of our competitors, however,
obtain a significant portion of their feedstocks from company-owned
production. Competitors that have their own production, with brand-name
recognition, are at times able to offset losses from refining operations with
profits from producing or relating operations, and may be better positioned to
withstand periods of depressed refining margins or feedstock shortages. A
number of our competitors also have materially greater financial and other
resources we possess. These competitors have a greater ability to bear the
economic risks inherent in all phases of the refining industry. In addition,
we compete with other industries that provide alternative means to satisfy the
energy and fuel requirements of industrial, commercial and individual
consumers. If we are unable to compete effectively with these competitors,
both within and outside of the industry, our financial condition and results
of operations, as well as our business prospects, could be materially
adversely affected.

OUR SUBSTANTIAL INDEBTEDNESS MAY LIMIT OUR FINANCIAL FLEXIBILITY.

Our substantial indebtedness has significantly affected our financial
flexibility historically and may significantly affect our financial
flexibility in the future. As of December 31, 2001, we had total consolidated
long-term debt of $542.6 million and unrestricted cash of $222.8 million. As
of December 31, 2001, we had stockholders' equity of $242.3 million, resulting
in a total long-term debt to total capital ratio of 69.1%. We may also incur
additional indebtedness in the future, although our ability to do so will be
restricted by the terms of our existing indebtedness. The level of our
indebtedness has several important consequences for our future operations,
including that:

o a significant portion of our cash flow from operations will be
dedicated to the payment of principal of, and interest on, our
indebtedness and will not be available for other purposes;

o covenants contained in our existing debt arrangements require us
to meet or maintain certain financial tests, which may affect
our flexibility in planning for, and reacting to, changes in our
industry, such as being able to take advantage of acquisition
opportunities when they arise;

o our ability to obtain additional financing for working capital,
capital expenditures, acquisitions, general corporate and other
purposes may be limited;

o we may be at a competitive disadvantage to those of our
competitors that are less leveraged; and

o we may be more vulnerable to adverse economic and industry
conditions.

RESTRICTIVE COVENANTS IN OUR DEBT INSTRUMENTS MAY LIMIT OUR ABILITY TO
CONSUMMATE CERTAIN TRANSACTIONS.

Various restrictive covenants in our debt instruments may restrict our
financial flexibility in a number of ways. Our indebtedness subjects us to
significant financial and other restrictive covenants, including restrictions
on our ability to incur additional indebtedness, place liens upon assets, pay
dividends or make certain other restricted payments and investments,
consummate certain asset sales or asset swaps, enter into certain transactions
with affiliates, enter into sale and leaseback transactions, conduct
businesses other than our current businesses, merge or consolidate with any
other person or sell, assign, transfer, lease, convey or otherwise dispose of
all or substantially all of our assets. Some of our debt instruments also
require us to satisfy or maintain certain financial condition tests. Our
ability to meet these financial condition tests can be affected by events
beyond our control and we may not meet such tests.

WE HAVE SIGNIFICANT PRINCIPAL PAYMENTS UNDER OUR INDEBTEDNESS COMING DUE IN
THE NEXT SEVERAL YEARS; WE MAY BE UNABLE TO REPAY OR REFINANCE SUCH
INDEBTEDNESS.

We have significant principal payments due under our debt
instruments. We will be required to make the following principal payments on
our long-term debt: $79.6 million in 2002; $32.1 million in 2003; $47.4
million in 2004; $66.0 million in 2005; $54.4 million in 2006; and $263.1
million in the aggregate thereafter. In accordance with the secured account
structure, on January 15, 2002, Port Arthur Finance made a $59.7 million
mandatory prepayment of debt under its bank senior loan agreement.

Our ability to meet our principal obligations will be dependent upon
our future performance, which in turn will be subject to general economic
conditions, industry cycles and financial, business and other factors
affecting our operations, many of which are beyond our control. Our business
may not continue to generate sufficient cash flow from operations to repay our
substantial indebtedness. If we are unable to generate sufficient cash flow
from operations, we may be required to sell assets, to refinance all or a
portion of our indebtedness or to obtain additional financing. Refinancing may
not be possible and additional financing may not be available on commercially
acceptable terms, or at all.

COMPLIANCE WITH, AND CHANGES IN, ENVIRONMENTAL LAWS COULD ADVERSELY AFFECT OUR
RESULTS OF OPERATIONS AND OUR FINANCIAL CONDITION.

We are subject to extensive federal, state and local environmental
laws and regulations, including those relating to the discharge of materials
into the environment, waste management, pollution prevention, remediation of
contaminated sites and the characteristics and composition of gasoline and
diesel fuels. In addition, some of these laws and regulations require our
facilities to operate under permits that are subject to renewal or
modification. These laws and regulations and permits can often require
expensive pollution control equipment or operational changes to limit impacts
or potential impacts on the environment and/or health and safety. A violation
of these laws and regulations or permit conditions can result in substantial
fines, criminal sanctions, permit revocations and/or facility shutdowns.
Compliance with environmental laws and regulations significantly contributes
to our operating costs. In addition, we have made and expect to make
substantial capital expenditures on an ongoing basis to comply with
environmental laws and regulations.

In addition, new laws, new interpretations of existing laws,
increased governmental enforcement of environmental laws or other developments
could require us to make additional expenditures. These expenditures or costs
for environmental compliance could have a material adverse effect on our
financial condition and results of operations. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Cash Flows from Investing Activities." For example, the EPA has
promulgated new regulations under the federal Clean Air Act that establish
stringent sulfur content specifications for gasoline and low-sulfur highway, or
"on-road" diesel fuel designed to reduce air emissions from the use of these
products.

In February 2000, the 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 the Port
Arthur refinery, including our heavy oil processing facility, as a result of
the Tier 2 standards. Based on our current estimates, we believe that
compliance with the new Tier 2 gasoline specifications will require capital
expenditures in the aggregate through 2005 of approximately one million
dollars for our facility.

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, 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. We estimate our capital expenditures in the aggregate through 2006
required to comply with the diesel standards at our heavy oil processing
facility, utilizing existing technologies, is approximately $110 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. We
intend to coordinate the investment to comply with these new specifications with
a potential joint project with PRG to expand the crude oil throughput capacity
of the Port Arthur refinery to 300,000 bpd. We believe this project, combined
with the low sulfur gasoline and diesel fuel investments, will offer a
reasonable return on capital.

ENVIRONMENTAL CLEAN-UP AND REMEDIATION COSTS OF OUR SITE COULD DECREASE OUR NET
CASH FLOW, REDUCE OUR RESULTS OF OPERATIONS AND IMPAIR OUR FINANCIAL CONDITION.

We are subject to liability for the investigation and clean-up of
environmental contamination at the property that we lease. There is extensive
contamination at the Port Arthur refinery site. PRG has agreed to retain
liability regarding contamination existing at the heavy oil processing facility
site as of the date of the lease agreement for such site and has indemnified us
against such liability. However, if PRG fails to satisfy its obligations for any
reason, or if significant liabilities arise with respect to future
contamination, we may become responsible for the remediation. If we are forced
to assume liability for the cost of this remediation, such liability could have
a material adverse effect on our financial condition. See "Business--
Environmental Matters and--Environmental Remediation."

WE HAVE HAD LIMITED OPERATING EXPERIENCE WITH THE NEW COKER UNIT AND OTHER
EQUIPMENT CONSTRUCTED AS PART OF THE HEAVY OIL UPGRADE PROJECT AT THE PORT
ARTHUR REFINERY AND MAY EXPERIENCE AN INTERRUPTION OF OUR COKER OPERATIONS.

Although we completed construction of the heavy oil processing
facility at our Port Arthur refinery in December 2000 and commenced operation
of the facility in the first quarter of 2001, we have a limited operating
history associated with the newly constructed facility and related equipment.
Therefore, we cannot be sure that the facility will continue to operate as
designed or that it will be integrated effectively with the rest of the units
and equipment at the Port Arthur refinery. Failure of the facility to operate
successfully could have a material adverse impact on our earnings, other
results of operations and financial condition.

A SUBSTANTIAL PORTION OF OUR WORKFORCE IS UNIONIZED AND WE MAY FACE LABOR
DISRUPTIONS THAT WOULD INTERFERE WITH OUR REFINERY OPERATIONS.

As of December 31, 2001, we employed 51 people, approximately 90% of
whom are covered by a collective bargaining agreement which expires in January
2006. Our relationships with the relevant unions have been good and we have
never experienced a work stoppage as a result of labor disagreements; however,
we cannot assure you that this situation will continue. A labor disturbance
could have a material adverse effect on our operations.

ITEM 3. LEGAL PROCEEDINGS

We are not aware of any material legal proceedings involving us, or
any of our subsidiaries.

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

There were no matters submitted to a vote of security holders during
the fourth quarter of our fiscal year ended December 31, 2001.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER
MATTERS

Our common stock is not publicly traded.

ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial data set forth in the table below
as of December 31, 2000 and 2001, for the period from May 4, 1999 (date of
inception) to December 31, 1999, and for each of the two years in the period
ended December 31, 2001 are derived from the audited financial statements
included elsewhere in this Form 10-K. The selected financial data set forth
below as of December 31, 1999 are derived from audited financial statements
not included in this Form 10-K. This table should be read in conjunction with
Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the Consolidated Financial Statements and related
notes included elsewhere herein.

PERIOD FROM MAY
4, 1999 TO YEAR ENDED DECEMBER 31,
DECEMBER 31, ----------------------------------
1999 (1) 2000 (1) 2001
------------------ ---------------- -----------------
(IN MILLIONS, EXCEPT AS NOTED)

STATEMENT OF EARNINGS DATA:
Net sales and operating revenues from affiliate........... $ -- $ 100.3 $ 1,882.4
Cost of sales............................................. -- 83.6 1,460.2
------------------ ---------------- -----------------
Gross margin............................................ -- 16.7 422.2
Operating expenses........................................ -- 10.2 140.4
General and administrative expenses....................... 3.1 1.1 4.1
Depreciation ............................................. -- -- 20.5
------------------ ---------------- -----------------
Operating income (loss)................................... (3.1) 5.4 257.2
Interest expense and finance income, net (2).............. (10.8) (3.2) (60.1)
------------------ ---------------- -----------------
Income (loss) before income taxes......................... (13.9) 2.2 197.1
Income tax (provision) benefit ........................... -- 4.1 (69.0)
------------------ ---------------- -----------------
Net income (loss)......................................... $ (13.9) $ 6.3 $ 128.1
================== ================ =================
CASH FLOW DATA:
Cash flows from operating activities...................... $ 29.1 $ 2.3 $ 205.0
Cash flows from investing activities...................... (427.2) (215.8) (12.1)
Cash flows from financing activities...................... 398.2 249.8 (6.5)
EBITDA (3)................................................ (3.1) 5.4 277.7
Expenditures for property, plant and equipment............ 380.6 262.4 12.1
KEY OPERATING STATISTICS:
Production (barrels per day in thousands)................. -- 10.1 197.8
Crude throughput (barrels per day in thousands) .......... -- 8.9 186.0
Per barrel of crude oil throughput
Gross margin ........................................... $ -- $ 5.11 $ 6.22
Operating expenses ..................................... -- 3.10 2.07

AS OF DECEMBER 31,
----------------------------------------------------
1999 2000 2001
------------------ ---------------- ----------------

BALANCE SHEET DATA:
Cash, cash equivalents and short-term investments......... $ -- $ 36.4 $ 222.8
Working capital .......................................... (42.4) 1.1 102.0
Total assets ............................................. 446.6 802.7 979.1
Long-term debt............................................ 360.0 542.6 463.0
Stockholders' equity...................................... 43.3 114.2 242.3

(1) Operations of our heavy oil upgrade facility commenced in early December
2000. Financial results in the pre-operating stage related primarily to
the construction and financing of the facility.
(2) Interest expense and financing income, net, included amortization of debt
issuance costs of $1.0 million, $4.0 million, and $6.5 million for the
periods ended December 31, 1999, 2000 and 2001, respectively. Interest
expense and financing income, net, also included interest on all
indebtedness, net of capitalized interest and interest income. Included
in 1999 were financing charges related to the initial financing of our
heavy oil upgrade project.
(3) Earnings before interest, taxes, depreciation and amortization, or
EBITDA, is a commonly used non-GAAP financial measure but should not be
construed as an alternative to operating income or net income as an
indicator of our performance, nor as an alternative to cash flows from
operating activities, investing activities or financing activities as a
measure of liquidity, in each case as such measures are determined in
accordance with generally accepted accounting principles, or GAAP. EBITDA
is presented because we believe that it is a useful indicator of a
company's ability to incur and service debt and, as we calculate it, may
not be comparable to similarly-titled measures reported by other
companies.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

OVERVIEW AND RECENT DEVELOPMENTS

We were formed to develop, construct, own, operate, and finance a heavy
oil processing facility that includes a new 80,000 bpd delayed coking unit, a
35,000 bpd hydrocracker unit, and a 417 long tons per day sulfur complex that
are operated in conjunction with the refining assets at the Port Arthur, Texas
refinery of our affiliate, The Premcor Refining Group Inc., or PRG. This heavy
oil processing facility, along with modifications made by PRG at its Port Arthur
refinery, allows the refinery to process primarily lower-cost, heavy sour crude
oil. We were incorporated in May of 1999 and were capitalized in August of 1999.
We are the 1% general partner of PACC and the 100% owner of Neches River Holding
Corp., which is the 99% limited partner of PACC. We are owned 90% by Premcor
Inc. and 10% by Occidental.

In January 2001, we began full operation of our newly constructed
coking, hydrocracking and sulfur removal units. PRG began construction of these
new units in 1998. In the third quarter of 1999, we purchased a portion of the
work in progress and certain other related assets from PRG. We financed and
completed the construction of the heavy oil processing facility. Start-up of the
units occurred in stages, with the sulfur removal units and the coker unit
beginning operations in December 2000 and the hydrocracker unit beginning
operations in January 2001. Substantial reliability, as defined in our financing
documents and construction contracts, of the heavy oil processing facility was
achieved as of September 30, 2001, and final completion was achieved as of
December 28, 2001.

We entered into agreements with PRG associated with the operations of
our heavy oil processing facility and PRG's Port Arthur refinery, including
supply and services, product purchase, and ancillary unit lease agreements as
described below:

o We lease 100% of PRG's crude, vacuum and other ancillary units for
a quarterly lease fee, which is reported as an operating expense.
PRG utilizes, through the processing arrangement discussed below,
approximately 20%, or 50,000 bpd of crude distillation capacity
and this is recorded as revenue. As a result of this arrangement,
we are utilizing approximately 80%, or 200,000 bpd, of the Port
Arthur refinery's crude distillation capacity.

o Our production consists of intermediate refined products and
lesser volumes of petroleum coke and sulfur, all of which are sold
at fair market value to PRG for either further processing into
higher value finished refined products or immediate sale to third
parties.

o PRG utilizes a portion of the capacity of our heavy oil processing
facility for a monthly processing fee. This fee is recorded as an
offset to our operating expenses.

o We pay PRG a fee for providing certain services and supplies,
including employee, maintenance and energy costs. These fees are
included in our operating expenses. We also pay PRG for pipeline
access and the use of its Port Arthur refinery dock. These fees
are included in cost of sales.

FACTORS AFFECTING OPERATING RESULTS

Our earnings and cash flow from operations are primarily affected by
the relationship between intermediate and refined product prices and the
prices for crude oil. The cost to acquire feedstocks and the price for which
intermediate and refined products are 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 how the prices of refined products adjust
to reflect such changes.

Feedstock, intermediate 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 costs and the
price of intermediate and refined products have historically been subject to
wide fluctuations. Expansion of existing facilities and installation of
additional refinery crude distillation and upgrading facilities, price
volatility, international political and 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 an increased
demand 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 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. The Port Arthur refinery configuration
is unique and has logistical advantages to a benchmark refinery, and as a
result, our gross margin per barrel of throughput differs from the benchmark
crack spread.

Of total feedstocks, we are able to process up to 80% heavy sour
crude oil that has historically cost less than West Texas Intermediate crude
oil. We measure the cost advantage of heavy crude oil by calculating the
spread between the value of Maya crude oil produced in Mexico to the value of
West Texas Intermediate crude oil because Maya is our predominant heavy sour
crude oil. The cost advantage of sour crude oil is benchmarked by calculating
the spread between the value of West Texas Sour crude oil to the value of West
Texas Intermediate crude oil.

The sales value of our production is also an important consideration in
understanding our results. Our product slate is substantially comprised of
intermediate refined products that are sold to PRG for further processing. Since
intermediate refined products carry a value lower than finished refined
products, our typical product slate carries a sales value lower than that for
the products used to calculate the Gulf Coast crack spread.

Our operating cost structure is also important to our profitability.
Major operating costs include energy, employee and contract labor, lease fees,
maintenance, 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.

Safety, reliability and the environmental performance of our heavy
oil processing facility and the Port Arthur refinery in general are critical
to our financial performance. Unplanned downtime of refinery assets generally
results in lost margin opportunity, increased maintenance expense and a
temporary increase in working capital investment and related inventory
position. 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. As petroleum feedstocks and intermediate
products are essentially commodities, we have no control over the changing
market value of our investment. Because most of our titled inventory is valued
under the first-in, first-out costing method, price fluctuations on our titled
inventory can have material effects on our financial results. Our petroleum
inventories consist principally of crude oil since we sell all of our production
to PRG under the product purchase agreement.

We have a long-term crude oil supply agreement with P.M.I. Comercio
International, S.A. de C.V., an affiliate of PEMEX, the Mexican state oil
company, that provides us with a stable and secure supply of Maya crude oil. An
important feature of this agreement is a price adjustment mechanism designed to
minimize the effect of adverse refining margin cycles and to moderate the
fluctuations of the coker gross margin, a benchmark measure of the value of
coker production over the cost of coker feedstocks. This price adjustment
mechanism contains a formula that represents an approximation of the coker gross
margin and provides for a minimum average coker margin of $15 per barrel over
the first eight years of the agreement, which began on April 1, 2001. The
agreement expires in 2011.

As of December 31, 2001, as a result of the favorable market conditions
related to the value of Maya crude oil versus the refined products derived from
it, a cumulative quarterly surplus of $110.0 million existed under the contract.
As a result, to the extent we experience quarterly shortfalls in coker gross
margins going forward, the price we pay for Maya crude oil in succeeding
quarters will not be discounted until this cumulative surplus is offset by
future shortfalls.

INDUSTRY OUTLOOK

Earnings for the refining industry have been and will continue to be
volatile. The cost of crude oil and the prices of intermediate and finished
refined products fluctuated widely in the past. Crude oil costs and refined
product prices depend on numerous factors beyond the refiner's 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, over the long-term,
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 refining industry margins summarized below
gives some indication of the volatility that exists in the industry.

On a full year basis, the 2001 refining margins exceeded the prior
year, which was also a very strong year. 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 refining margin achieved over the first half of
2001 was approximately twice the average for the first six month periods over
the last four years.

During the ensuing seven 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, 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. Notwithstanding a decrease in
consumer demand as a result of high prices and a weakening economy, refining
margins strengthened in August and early September 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 led to higher product
inventories. Mild winter weather, decreases in air travel compared to historic
levels, a weak industrial sector, and the overall downturn in the economy
resulted in inventories remaining at high levels at year-end and reduced
refining margins to very low levels. This trend continued in the first two
months of 2002.

The average discounts on sour and heavy sour crude oil for 2001
exceeded the prior year, reaching record levels in the first half of 2001, then
declining in the second half of 2001. Average discounts for sour and heavy sour
crude oil increased in the first half of 2001 from already favorable 2000 levels
due to increasing worldwide production of sour and heavy sour crude oil relative
to the production of light sweet crude oil coupled with the continuing high
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 and then narrowed from these record highs. These crude oil discounts
narrowed in the second half of 2001 partly due to the significant drop in crude
oil prices, particularly following the terrorist attacks of September 11th.
Lower crude oil prices generally result in smaller differentials between light
and heavy crude oil. Sweet crude oil continues to trade at a premium to West
Texas Sour crude oil 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 is a significant component of a refiner's
overall operating costs. Natural gas prices peaked at over $10 per million btu
in late 2000 and early 2001, but fell steadily throughout the remainder of 2001,
dropping to below $2 per million btu for a period of time. As production rates
and inventories of natural gas remain at higher levels than last year, we
believe prices will remain at levels well below the record highs seen in the
first quarter of 2001.

Refining margins have remained at depressed levels early in 2002 as
high distillate and gasoline inventories and low demand continued. The average
Gulf Coast spread for the first two months of 2002 was $2.12 per barrel as
compared to the 2001 full year average of $4.22 per barrel. The average discount
on heavy sour crude oil for the first two months of 2002 was $5.66 per barrel as
compared to the 2001 full year average of $8.76 per barrel. In March 2002,
refining margins began slowly recovering from these lows. As we enter the spring
and summer driving season, there is optimism that demand for gasoline and
distillates will increase, especially with the expected increase in driving as a
replacement for air travel. Uncertainty about distillate and gasoline demand as
well as crude oil supply, particularly the supply from the Middle East, will
continue to exist as the war on terrorism continues; however, steady improvement
in the economy should contribute to continued improvement in refining margins in
the second half of 2002.

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 refinery closures resulting from more stringent environmental
specifications and 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 should 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, should support strong differentials
relative to historic averages between the prices of 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.

OPERATIONAL OUTLOOK

On January 4, 2002, we shut down the sulfur complex for planned
turnaround maintenance. The turnaround was completed as scheduled without
disruption. All units were in service as planned by February 11, 2002. On
February 25, 2002, we shut down the coker unit for unplanned maintenance for
ten days. Crude oil throughput rates were cut back during these repairs. By
March 6, 2002 all units were operational and by March 7th crude oil throughput
rates were near capacity of 250,000 bpd.

RESULTS OF OPERATIONS

The following table provides supplementary income statement and
operating data. It does not represent an income statement presented in
accordance with generally accepted accounting principles. Selected items in
each of the periods are discussed separately below.

Net sales and operating revenues consist principally of sales of
intermediate refined petroleum products and, to a minimal extent, the
occasional sale of crude oil to take advantage of substitute crude slate
opportunities. Cost of sales consists of the purchases of crude oils and other
feedstocks used in the refining process as well as transportation, inventory
management and other costs associated with the refining process and sale of
the petroleum products. Both net sales and operating revenues and cost of
sales are mainly affected by crude oil and refined product prices and changes
to the input and product mix. Product mix refers to the percentage of
production represented by higher value light products, such as gasoline
blendstocks, rather than lower value finished products, such as petroleum
coke.

Gross margin is net sales and operating revenues less cost of sales.
Industry-wide results are driven and measured by the relationship, or margin,
between intermediate and finished product prices and the prices for crude oil
and other feedstocks; therefore, we discuss our results of operations in the
context of gross margin.

Operating expenses include the costs associated with the actual
operations of the heavy oil processing facility and our portion of the
operations related to the lease of units from PRG, such as labor, maintenance,
energy, taxes and environmental compliance. All environmental compliance costs,
other than capital expenditures but including maintenance and monitoring, are
expensed when incurred. The labor costs include the incentive compensation plans
available to union employees. Our general and administrative expenses include
expenses for certain management and financial services provided by PRG and other
administrative costs.

FINANCIAL RESULTS PERIOD FROM MAY
4, 1999 TO YEAR ENDED DECEMBER 31,
DECEMBER 31, --------------------------------------
1999 (1) 2000 (1) 2001
------------------ ------------------- ----------------
(IN MILLIONS, EXCEPT AS NOTED)

Net sales and operating revenues...................... $ -- $ 100.3 $ 1,882.4
Cost of sales......................................... -- 83.6 1,460.2
------------------ ------------------- ----------------
Gross Margin...................................... -- 16.7 422.2
Operating expenses.................................... -- 10.2 140.4
General and administrative expenses................... 3.1 1.1 4.1
Depreciation.......................................... -- -- 20.5
------------------ ------------------- ----------------
Operating income (loss)........................... (3.1) 5.4 257.2
Interest expense and finance income, net.............. (10.8) (3.2) (60.1)
Income tax (provision) benefit........................ -- 4.1 (69.0)
------------------ ------------------- ----------------
Net income (loss)................................. $ (13.9) $ 6.3 $ 128.1
================== =================== ================

MARKET INDICATORS PERIOD FROM MAY
4, 1999 TO YEAR ENDED DECEMBER 31,
DECEMBER 31, ------------------------------------
1999 (1) 2000 (1) 2001
------------------ ------------------ -----------------
(DOLLARS PER BARREL, EXCEPT AS NOTED)

West Texas Intermediate (WTI) crude oil................ $ 19.27 $ 30.37 $ 25.96
Gulf Coast Crack Spread (3/2/1) ....................... 1.71 4.17 4.22
Crude Oil Differentials:
WTI less WTS (sour) ................................ 1.30 2.17 2.81
WTI less Maya (heavy sour).......................... 4.83 7.29 8.76
WTI less Dated Brent (foreign) ..................... 1.36 1.92 1.48
Natural gas (dollars per million btus)................. 2.25 3.94 4.22

SELECTED VOLUMETRIC AND PER BARREL DATA PERIOD FROM MAY
4, 1999 TO YEAR ENDED DECEMBER 31,
DECEMBER 31, ------------------------------------
1999 (1) 2000 (1) 2001
------------------ ------------------ -----------------
(IN THOUSANDS OF BARRELS PER DAY, EXCEPT AS NOTED)

Production ............................................. -- 10.1 197.8

Crude oil throughput .................................. -- 8.9 186.0
Per barrel of throughput (in dollars):
Gross margin......................................... -- $ 5.11 $ 6.22
Operating expenses................................... -- 3.10 2.07

(1) Operations of our heavy oil processing facility commenced in early
December of 2000. Financial results in the pre-operating stage related
primarily to the construction and financing of the facility.

YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 (a) 2001
SELECTED VOLUMETRIC DATA ------------------- -------------------
PERCENT PERCENT
BARRELS OF TOTAL BARRELS OF TOTAL
------- -------- --------- --------
(IN THOUSANDS OF BARRELS PER DAY)

FEEDSTOCKS:
Crude oil throughput:
Light/medium sour....................... 3.6 40.4% 38.0 20.4%
Heavy sour.............................. 5.3 59.6 148.0 79.6
----- ----- ------ -----
Total crude oil....................... 8.9 100.0% 186.0 100.0%
===== ===== -===== =====

PRODUCTION:
Intermediate production ................... 8.8 87.1% 180.0 91.0%
Petroleum coke and sulfur.................. 1.3 12.9 17.8 9.0
----- ----- ------ -----
Total production...................... 10.1 100.0% 197.8 100.0%
===== ===== ====== =====

(a) Operations of our heavy oil processing facility commenced in early
December of 2000.

2001 COMPARED TO 2000

Overview. Net income increased $121.8 million to $128.1 million in 2001
from $6.3 million in 2000. Operating income increased $251.8 million to $257.2
million in 2001 from $5.4 million in 2000. The operating results for 2001
compared to 2000 were affected by the completion of construction and
commencement of operations of the heavy oil processing facility. The heavy oil
processing facility was partially operational during December of 2000 with full
operations beginning in January of 2001. See "--Overview and Recent
Developments" and "--Factors Affecting Operating Results" for a detailed
discussion of how the completion of the heavy oil upgrade project has affected
our results.

Net Sales and Operating Revenue. Net sales and operating revenues
increased $1,782.1 million to $1,882.4 million in 2001 from $100.3 million in
2000.

Gross Margin. Gross margin increased $405.5 million to $422.2 million
in 2001 from $16.7 million in 2000. The year of 2001 reflected strong market
conditions in the first half of the year, partially offset by operational
issues and slowing market conditions in the last half of the year. For 2001,
our gross margin benefited from the strong crude oil discounts reflected in
the significant differentials between WTI and sour and heavy sour crude oil
and improvements to refining margins as reflected in the Gulf Coast crack
spread.

Crude oil throughput rates averaged 8,900 bpd and 186,000 bpd, of the
available 200,000 bpd, in 2000 and 2001, respectively. Crude oil throughput
rates in 2001 were restricted because units downstream were in start-up
operations during the first quarter and a lightning strike in early May
limited the crude unit rate until the crude unit was shut down in early July
for ten days to repair damage caused by the lightning strike. The crude unit
throughput rates were close to capacity during the months of August through
December of 2001, with some minor restrictions late in 2001 for coker and
crude unit repairs.

The 80,000 bpd coker unit averaged approximately 75,200 bpd in 2001.
Overall throughput rates were lower than capacity due to the restrictions from
the lightning strike, a planned maintenance turnaround of PRG's alkylation unit,
the fine tuning of operations associated with the start-up of our coker and
hydrocracker units, and some repairs performed late in the fourth quarter.

Operating Expenses. Operating expenses increased $130.2 million to
$140.4 million in 2001 from $10.2 million in 2000. Operating expenses included
employee, catalyst/chemical, repair and maintenance, insurance, taxes,

and energy costs as well as costs, net of lease fees, related to the service
and supply agreement with PRG.

General and Administrative Expenses. General and administrative
expenses increased $3.0 million to $4.1 million in 2001 from $1.1 million in
2000. The 2001 general and administrative expenses primarily included costs
associated with the services and supply agreement with PRG. This agreement did
not take effect until the fourth quarter of 2000. The 2000 general and
administrative expenses primarily included employee and professional fee
expenses related to the pre-operation period.

Depreciation. Depreciation was nil and $20.5 million in 2000 and 2001,
respectively. We began depreciating our assets in accordance with our property,
plant and equipment policy during the first quarter of 2001, following the
substantial completion of the heavy oil upgrade project in stages, beginning
December 2000 and full commencement of operations in January 2001.

Interest Expense and Finance Income, net. Interest expense and
finance income, net increased $56.9 million to $60.1 million in 2001 from $3.2
million in 2000. In 2000, the majority of the interest costs were capitalized
as part of the heavy oil upgrade project. These costs were expensed in 2001
upon the completion of the project. The increase was partially offset by
decreases in our interest rate on our floating rate bank senior loan
agreement.

Income Tax Provision. The income tax provision increased $73.1
million to $69.0 million in 2001 from an income tax benefit of $4.1 million in
2000. The income tax provision of $69.0 million in 2001 represented an
approximate 35% effective tax rate on pretax income. In 2001, under the terms
of our tax sharing agreement with the common parent of our consolidated group,
Premcor Inc., and the common security agreement related to our senior debt, we
made a federal estimated income tax payment of $13.0 million. See Note 14.
"Income Taxes" to the Consolidated Financial Statements.

2000 COMPARED TO 1999

Overview. Net income increased by $20.2 million from a net loss of
$13.9 million in 1999 to net income of $6.3 million in 2000. Operating income
increased $8.5 million to $5.4 million in 2000 from a loss of $3.1 million in
1999. From inception to November 2000, we were in a construction and
pre-operation stage and had no material operating revenues or expenses.

Net Sales and Operating Revenues. Net sales and operating revenues
increased to $100.3 million in 2000 from nil in 1999. This increase was due to
the fact that parts of the heavy oil processing facility began operations and
started revenue generation in December 2000.

Operating Expenses. Operating expenses increased to $10.2 million in
2000 from nil in 1999. Operating expenses for the year ended December 31, 2000
included pre-operating as well as operating expenses.

General and Administrative Expenses. General and administrative
expenses were $3.1 million in 1999 and $1.1 million in 2000. The 1999 and 2000
general and administrative expenses primarily included employee and
professional fee expenses related to the pre-operation period.

Interest Expense and Finance Income, net. Interest expense and
finance income, net decreased approximately 70% to $3.2 million in 2000 from
$10.8 million in 1999. Of this decrease, $7.6 million related to the absence
in 2000 of start-up costs associated with the initial financing of the heavy
oil processing facility. For both 2000 and 1999, the majority of the interest
expense from the debt incurred to finance the heavy oil upgrade project was
capitalized as part of the project.

Income Tax Benefit. The income tax benefit of $4.1 million in 2000
represents a provision on income of $0.8 million offset by the effect of a
decrease in the deferred tax valuation allowance of $4.9 million. The fact
that no 1999 income tax benefit was recorded on the loss reflected the
increase in the deferred tax valuation allowance of $4.9 million. See Note 14.
"Income Taxes" to the Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

Cash Balances

As of December 31, 2001, we had a cash and cash equivalent balance of
$222.8 million. Under a common security agreement related to our senior debt,
this cash is reserved under a secured account structure for specific
operational uses and mandatory debt repayment. The operational uses include
various levels of spending, such as current and operational working capital
needs, interest and principal payments, taxes, and maintenance and repairs.
Cash is applied to each level until that level has been fully funded, upon
which the remaining cash flows to the next level. Once these spending levels
are funded, any cash surplus satisfies obligations of a debt service reserve
and mandatory debt prepayment with funding occurring semiannually on January
15th and July 15th. In addition, we had $30.8 million of cash and cash
equivalents restricted for debt service, which included a principal payment of
$6.5 million and interest payments of $24.3 million due in January of 2002.
On January 15, 2002 we used $59.7 million of cash to make a mandatory prepayment
of our bank senior loan agreement under this secured account structure.

Cash Flows from Operating Activities

Cash flows provided by operating activities for the year ended
December 31, 2001 was $205.0 million compared to $2.3 million for the year
ended December 31, 2000 and $29.1 million for the period ended December 31,
1999. These cash flows mainly resulted from the earnings from operations in
2001 and the loss during the development stage in 2000 and 1999. Working
capital changes were principally due to the shift from accounts payable
related solely to capital expenditure accruals to accounts receivable,
accounts payable and inventory related to full operations.

Cash restricted for principal and interest payments of our debt was
classified as a current asset and the changes to this restricted cash were
reflected in financing activities as it related to principal payments and
operating activities as it related to interest payments. In 2001, $24.3
million was restricted for interest payments to be made in January of 2002 and
was part of the $30.8 million cash and cash equivalents restricted for debt
service.

As of December 31, 2001, our future minimum lease payments under
non-cancelable operating leases were as follows (in millions): 2002--$33.2;
2003--$33.2; 2004--$33.2; 2005--$33.2; 2006--$33.2; and $664.0 in the aggregate
in 2007 and thereafter. These lease payments relate to our agreement with PRG to
lease 100% of their crude, vacuum and other ancillary units for a 30-year term.

Cash Flows from Investing Activities

Cash flows used in investing activities were $12.1 million for the
year ended December 31, 2001 as compared to $215.8 million in 2000 and $427.2
million in 1999. Expenditures for property, plant and equipment in 1999, 2000
and 2001 were primarily associated with the construction of the heavy oil
processing facility. All proceeds from our 1999 debt financings were restricted
for use on the construction, financing, and start-up operations of the heavy
oil processing facility. As a result, cash and cash equivalents associated with
the construction of the heavy oil processing facility were classified as a
non-current asset and the restricted cash and cash equivalent activity was
reflected as investing activity in 2000.

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 $10
million per year over the next five years. This estimate includes the capital
costs necessary to comply with environmental regulations, except for Tier 2
gasoline standards and on-road diesel regulations described below.
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. In 2001, our discretionary capital expenditures
of $11.9

million related to the completion of the heavy oil processing facility. Our
discretionary capital expenditure budget for 2002 is approximately $9 million.

Environmental Product Standards

In addition to mandatory capital expenditures, we expect to incur costs
in conjunction with our affiliate, PRG, in order to comply with environmental
regulations as discussed below. The EPA 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.

Tier 2 Motor Vehicle Emission Standards. In February 2000, the 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 the Port Arthur refinery, including our heavy oil
processing facility, as a result of the Tier 2 standards. Based on our current
estimates, we believe that compliance with the new Tier 2 gasoline
specifications will require capital expenditures in the aggregate through 2005
of approximately one million dollars for our facility.

Low Sulfur Diesel Standards. 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, 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. We estimate our capital
expenditures in the aggregate through 2006 required to comply with the diesel
standards at our heavy oil processing facility, utilizing existing
technologies is approximately $110 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. We have initiated a project at our
Port Arthur refinery to comply with these new diesel fuel specifications in
conjunction with an expansion of this refinery to 300,000 bpd.

Cash Flows from Financing Activities

Cash flows used in financing activities were $6.5 million for the
year ended December 31, 2001 compared to cash flows provided by financing
activities of $249.8 million and $398.2 million for the years ended December
31, 2000 and 1999, respectively. Cash restricted for principal and interest
payments of our debt was classified as a current asset and the changes to this
restricted cash were reflected in financing activities as it related to
principal payments and operating activities as it related to interest
payments. In 2001, $6.5 million was restricted for January 2002 principal
payments and was part of the $30.8 million cash and cash equivalents
restricted for debt service. The 1999 and 2000 proceeds were comprised
principally of funding under the $255 million in 12 1/2% senior secured notes,
borrowings under the bank senior loan agreement, and required pro-rata
shareholder contributions received pursuant to capital contribution
agreements, all of which were used to fund the construction of the heavy oil
processing facility. The deferred financing costs in 2000 were associated with
the filing of documents with the Securities and Exchange Commission for the
registration of the 12 1/2 % senior secured notes.

We are a party, via our wholly-owned subsidiary, Port Arthur Finance
Corp., to the $325 million bank senior loan agreement entered into in
connection with the construction of the heavy oil processing facility. We have
borrowed $288 million under the facility to date. Our ability to draw the
balance under the $325 million bank senior loan agreement expired upon the
achievement of substantial reliability of the heavy oil upgrade project as
described below. Substantial reliability is a term in the construction
contract and the financing documents for the heavy oil processing facility
that referred to the date when Foster Wheeler demonstrated that the heavy oil
processing facility was sufficiently complete and could reliably generate
expected operating margins. We achieved substantial

reliability as of September 30, 2001, as required by our common security
agreement. We issued, also through our Port Arthur Finance Corp. subsidiary,
$255 million of 12 1/2% senior secured notes in connection with the project. The
debt under both such instruments is secured by liens on substantially all of the
assets owned by PACC at the Port Arthur refinery pursuant to a common security
agreement. The common security agreement requires us, for the benefit of our
senior lenders, to maintain a secured account structure containing a significant
amount of cash. We cannot utilize funds held in the secured account structure
for any other purpose. The impact of this secured account structure on our cash
flow varies, but restricts an estimated $200 million at any given time and
therefore may adversely affect our ability to undertake certain transactions. As
of December 31, 2001, we had cash and cash equivalents of $222.8 million, and
cash restricted for debt service of our long-term debt within the secured
account structure of $30.8 million. In accordance with the secured account
structure, on January 15, 2002, we made a $59.7 million mandatory prepayment of
debt under the bank senior loan agreement.

The scheduled maturities of our long-term debt during the next five
years are (in millions); 2002--$79.6; 2003--$32.1; 2004--$47.4; 2005--$66.0;
2006--$54.4; 2007 and thereafter--$263.1.

Credit Agreements

Under our senior debt documents, we are also required to establish a
debt service reserve account and, as of the date the heavy oil upgrade project
achieved substantial reliability, deposit or cause the deposit of an amount
equal to the next semiannual payment of principal and interest coming due from
time to time. In lieu of depositing funds into this reserve account at
substantial reliability, we arranged for Winterthur International Insurance
Company Limited, or Winterthur, to provide a separate debt service reserve
insurance policy in the maximum amount of $60 million for a period of
approximately five years from substantial reliability of the heavy oil upgrade
project. Payments will be made under this policy to pay debt service to the
extent we do not have sufficient funds available to make a debt service payment
on any scheduled semiannual payment date during the term of the policy.

We are party, via our Port Arthur Finance Corp subsidiary, to a $35
million working capital facility which is primarily used for the issuance of
letters of credit securing purchases of non-Maya crude oil. As of December 31,
2001, none of the facility was utilized for letters of credit. We are party,
via PACC, to an insurance policy under which an affiliate of American
International Group agreed to insure PEMEX's affiliate against a potential
default by us under the long-term crude oil supply agreement up to a maximum
liability of $40 million.

In order to provide security to PEMEX's affiliate for our obligation
to pay for shipments of Maya crude oil under the long-term crude oil supply
agreement, we obtained from Winterthur an oil payment guaranty insurance
policy for the benefit of PEMEX's affiliate. This oil payment guaranty
insurance policy is in the amount of $150 million and will be a source of
payment to PEMEX's affiliate if we fail to pay for one or more shipments of
Maya crude oil. Under our senior debt documents, any payments by Winterthur on
this policy are required to be reimbursed by us, and Winterthur has an equal
and ratable claim on all of the collateral for holders of our senior debt,
except in specified circumstances in which Winterthur has a senior claim to
these holders. As of December 31, 2001, $79.5 million of crude oil purchase
commitments were outstanding related to this policy.

Funds generated from operating activities together with existing cash
and cash equivalents are expected to be adequate to fund ongoing operating
requirements for the foreseeable future.

ACCOUNTING STANDARDS

Critical Accounting Standards

Contingencies. We account for contingencies in accordance with the
Financial Accounting Standards Board ("FASB") Statement of Financial
Accounting Standards ("SFAS") No. 5 Accounting for Contingencies. SFAS
No. 5 requires that we record an estimated loss from a loss contingency when
information available prior to the issuance of our financial statements
indicates that it is probable that an asset has been impaired or a liability
has been incurred at the date of the financial statements and the amount of
the loss can be reasonably estimated. Accounting for contingencies such as
environmental, legal and income tax matters require us to use our judgment.

While we believe that our accruals for these matters are adequate, if the
actual loss from a loss contingency is significantly different than the
estimated loss, our results of operations may be over or understated.

Inventories. Inventories for our company are stated at the lower of
cost or market. Cost is determined under the first-in, first-out ("FIFO")
method for hydrocarbon inventories including crude oil, refined products, and
blendstocks as well as warehouse stock and other inventories. Any reserve for
inventory cost in excess of market value is reversed if physical inventories
turn and prices recover above cost. At December 31, 2001, the carrying value of
our crude oil and refined product inventories approximated the replacement
cost (market value). As of December 31, 2001, we had 2.8 million barrels of
crude oil and refined product inventories with an average cost of $13.58 per
barrel. If the market value of these inventories had been lower by $1 per
barrel at December 31, 2001, we would have been required to write-down the
value of our inventory by $2.8 million. If prices decline dramatically near
the end of a period, we may be required to write-down the value of our
inventories in future periods.

New Accounting Standards

On July 20, 2001, the FASB issued SFAS No. 141 Business Combinations
and SFAS No. 142 Goodwill and Other Intangible Assets. SFAS No. 141, 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. The
implementation of SFAS No. 141 and SFAS No. 142 are not expected to have a
material impact on our financial position and results of operations.

In June 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
implementation of SFAS No. 143 is not expected to have a material impact on our
financial position or results of operation.

In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. This statement addresses financial
accounting and reporting for the impairment disposal of long-lived assets and
supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of, and the accounting and reporting
provisions of APB Opinion No. 30, Reporting the Results of Operations--Reporting
the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual
and Infrequently Occurring Events and Transactions, for the disposal of a
segment of a business (as previously defined in that Opinion). The provisions of
this statement are effective for financial statements issued for fiscal years
beginning after December 15, 2001 and interim periods within those fiscal years,
with early application encouraged. The implementation of SFAS No. 144 is not
expected to have a material impact on our financial position or results of
operation.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The risk inherent in our market risk sensitive instruments and
inventory positions is the potential loss from adverse changes in commodity
prices and interest rates. None of our market risk sensitive instruments are
held for trading.

COMMODITY RISK

Our earnings, cash flow and liquidity are significantly affected by a
variety of factors beyond our control, including the supply of, and demand
for, commodities such as crude oil, other feedstocks, intermediate products,
gasoline and other refined products. The demand for these refined products
depends on, among other factors, changes

in domestic and foreign economies, weather conditions, domestic and foreign
political affairs, planned and unplanned downtime in refineries, pipelines and
production facilities, production levels, the availability of imports, the
marketing of competitive fuels and the extent of government regulation. As a
result, crude oil and refined product prices fluctuate significantly, which
directly impacts our net sales and operating revenues and costs of goods sold.

The movement in petroleum prices does not necessarily have a direct
long-term relationship to net income. The effect of changes in crude oil
prices on our operating results is determined more by the rate at which the
prices of refined products adjust to reflect such changes. We are required to
fix the price on our crude oil purchases approximately two to three weeks
prior to the time when the crude oil can be processed and sold. As a result,
we are exposed to crude oil price movements relative to refined product price
movements during this period. In addition, earnings may be impacted by the
write-down of our FIFO based inventory cost to market value when market prices
drop dramatically compared to our FIFO inventory cost. These potential
write-downs may be recovered in subsequent periods as our inventories turn and
market prices rise. As of December 31, 2001, we had 2.8 million barrels of
crude oil and refined product inventories with an average cost of $13.58 per
barrel. If the market value of these inventories had been lower by $1 per
barrel we would have been required to write-down the value of our inventory by
$2.8 million. As of December 31, 2000, we had 2.4 million barrels of crude oil
and refined product inventories with an average cost of $18.38 per barrel. If
the market value of these inventories had been lower by $1 per barrel we would
have been required to write-down the value of our inventory by $2.4 million.
If prices decline dramatically near the end of a period, we may be required to
write-down the value of our inventories in future periods.

Interest Rate Risk

Our primary interest rate risk is associated with our long-term debt,
and we manage this risk by maintaining a mix of fixed and floating interest
rates on our long-term debt. A 1% change in the interest rate on the outstanding
debt under the floating rate bank senior loan agreement of $287.6 million would
result in a $2.9 million change in pretax income. We have the ability to call
our bank senior loan agreement debt at its principal amount and our 12 1/2%
senior secured notes with a make whole premium.

Under the common security agreement, we were required to hedge a
substantial portion of our floating rate exposure under the bank senior loan
agreement. We entered into a transaction in April 2000 that capped the London
Interbank Offered Rate ("LIBOR") at 7 1/2% for the following notional
principal outstanding amounts of our bank senior loan agreement (in millions):

LAST DATE OF CALCULATION PERIOD NOTIONAL AMOUNT OUTSTANDING
------------------------------- ---------------------------

July 15, 2000 $91.8
October 15, 2000 125.2
January 15, 2001 144.7
July 15, 2001 162.5
January 15, 2002 108.4
July 15, 2002 81.2
January 15, 2003 54.0
July 15, 2003 30.7
January 15, 2004 7.5

The interest rates on the Tranche A and B portion of the bank senior
loan agreement are based on the LIBOR plus a margin. This interest rate cap
policy covers April 2000 through January 2004.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is incorporated herein by
reference to Part IV, Item 14(a) 1 and 2, Financial Statements.

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

None.

PART III

ITEM. 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Our directors and executive officers and their respective ages as of
March 1, 2002 and positions are set forth in the table below.

NAME AGE POSITION
- ---- --- --------

Thomas D. O'Malley.......... 60 Chairman of the Board, President, Chief Executive
Officer and Chief Operating Officer
Stephen I. Chazen........... 55 Director
David I. Foley.............. 34 Director
Robert L. Friedman.......... 58 Director
William E. Haynes........... 58 Director
William E. Hantke........... 54 Executive Vice President and Chief Financial Officer
Jeffry N. Quinn............. 43 Executive Vice President and General Counsel

Thomas D. O'Malley has served as chairman, chief executive officer,
chief operating officer, president and a director of our company, each of our
subsidiaries and Premcor Inc. since February 2002. Mr. O'Malley served as vice
chairman of the board of Phillips Petroleum Company from the consummation of
that company's acquisition of Tosco Corporation in September 2001 until
January 2002. Mr. O'Malley served as chairman and chief executive officer of
Tosco from January 1990 to September 2001 and president of Tosco from May 1993
to May 1997 and from October 1989 to May 1990. He currently serves on the
board of directors of Lowe's Companies Inc.

Stephen I. Chazen has served as a director of our company and each of
our subsidiaries since July 1999 and as a director of Premcor Inc. since its
formation in April 1999. Mr. Chazen served as a director of Premcor Inc.'s
predecessor from December 1995 to April 1999. Mr. Chazen has served as
executive vice president--corporate development and chief financial officer
for Occidental Petroleum Corporation since February 1999. From May 1994 to
February 1999, Mr. Chazen served as executive vice president--corporate
development at Occidental Petroleum Corporation. From 1982 to April 1994, Mr.
Chazen served as an investment banker at Merrill Lynch & Co., Inc., where he
was a managing director. He currently serves on the governance committees of
Equistar Chemicals, LP and OxyVinyls, LP.

David I. Foley has served as a director of our company and each of
our subsidiaries since May 1999 and as a director of Premcor Inc. since its
formation in April 1999. Mr. Foley is a principal at The Blackstone Group L.P.,
which he joined in 1995. Prior to joining Blackstone, Mr. Foley was an employee
of AEA Investors Inc. from 1991 to 1993 and a consultant with The Monitor
Company from 1989 to 1991. He currently serves on the board of directors of Mega
Bloks Inc.

Robert L. Friedman has served as a director of our company since
October 1999 and each of our subsidiaries and as a director of Premcor Inc.
since July 1999. Mr. Friedman has served as a senior managing director of The
Blackstone Group L.P. since February 1999. From 1974 until the time he joined
Blackstone, Mr. Friedman was a partner with Simpson Thacher & Bartlett, a New
York law firm. He currently serves on the board of directors of American Axle
& Manufacturing, Inc., Axis Specialty Limited, Corp Group, Crowley Data LLC
and Republic Technologies International Holdings LLC.

William E. Haynes has served as a director and vice president of our
company and each of our subsidiaries since August 1999. He served as chairman
and chief executive officer of Innovative Valve Technologies Inc., an
industrial valve repair and distribution company, from May 1997 to January
2000 and as president from March 1997 to October 1998. Mr. Haynes has also
served as president and chief executive officer of Safe Seal, Inc., now a

subsidiary of Innovative Valve Technologies, from November 1996 through March
1997. From July 1993 to December 1995, Mr. Haynes served as president and
chief executive officer of Lyondell-Citgo Refining Company Ltd., a single
asset refining company. He has also served on the board of directors of Philip
Services Corp. and Innovative Valve Technologies Inc.

William E. Hantke has served as executive vice president and chief
financial officer of our company, each of our subsidiaries and Premcor Inc.
since February 2002. From 1990 to January 2002, Mr. Hantke served in various
positions with Tosco Corporation, most recently serving as Tosco's vice
president. He has held various finance and accounting positions in the oil
industry and other commodity industries since 1975.

Jeffry N. Quinn has served as executive vice president and general
counsel of our company, each of our subsidiaries and Premcor Inc. since March
2000. Mr. Quinn also served as chief administrative officer from March 2001 to
March 2002. He served as executive vice president--legal, human resources and
public affairs and general counsel of our company, each of our subsidiaries
and of Premcor Inc. from March 2000 to March 2001. From 1986 to February 2000,
Mr. Quinn held various executive positions with Arch Coal, Inc. and served as
senior vice president--law and human resources, secretary & general counsel
from 1995 to February 2000.

Under the certificates of incorporation of our company and each of our
subsidiaries, each company's board of directors must consist of five members
including an "independent director" who meets specified criteria intended to
ensure that such person does not have any potential for a direct or indirect
benefit from any activity involving PRG or its affiliates, other than
Blackstone, Occidental, us or our subsidiaries. The certificates of
incorporation also require that we, and each of our subsidiaries, have an
officer who meets similar criteria meant to ensure his or her independence. Mr.
Haynes currently serves as both the independent director and independent officer
of our company and each of our subsidiaries.

Under a certain stockholders' agreement between Premcor Inc. and
Occidental. Occidental has the right to designate one member of our board of
directors as long as it maintains a specified ownership interest in us. Mr.
Chazen was designated by Occidental to serve on our board of directors. For
further discussion of the stockholders' agreement between Premcor Inc. and
Occidental, see Item 13. "Certain Relationships and Related Transactions--Our
Relationship with Occidental Petroleum Corporation."

Director Compensation

Except for Mr. Haynes, our directors do not receive any compensation
for their services as directors. Mr. Haynes receives an annual retainer of
$10,000 plus an additional fee of $2,500 for each board meeting he attends and
for any other day he renders services to us. We also reimburse Mr. Haynes for
any legal fees that he incurs in fulfilling his obligations as an independent
director of our company and our subsidiaries. For 2001, Mr. Haynes received
$20,000 for his services as a director and $750 as reimbursement for legal
fees he incurred. All directors are reimbursed for their out-of-pocket
expenses incurred in attending board meetings.

ITEM 11. EXECUTIVE COMPENSATION

None of our executive officers are paid directly by us for their
services. Rather, services are provided to us, and each of our subsidiaries
under a services and supply agreement with PRG. For further discussion of the
services and supply agreement with PRG, see Note 12. "Related Party
Transactions--Premcor Refining Group--Services and Supply Agreement" to the
Consolidated Financial Statements.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Sabine River

The following table sets forth information concerning the beneficial
ownership of our stock as of March 1, 2002.

NUMBER OF PERCENT OF
NAME AND ADDRESS TITLE OF CLASS SHARES CLASS
---------------- -------------- --------- ----------

Premcor Inc.
8182 Maryland Avenue
St. Louis, Missouri 63105........................ Common 6,136,364 90%
Occidental Petroleum Corporation(1)
10889 Wilshire Boulevard
Los Angeles, California 90024.................... Common 711,818 10%

(1) Occidental Petroleum Corporation owns 681,818 shares of our common
stock and warrants representing the right to acquire 30,000 shares of
our common stock.

Premcor Inc.

The following table sets forth certain information concerning the
beneficial ownership of common stock of Premcor Inc. as of March 1, 2002 by
persons who beneficially own more than 5% of the outstanding shares of common
stock of Premcor Inc., each person who is a director of Premcor Inc., each
person who is a named executive officer of Premcor Inc., and all directors and
executive officers of Premcor Inc. as a group.

NUMBER PERCENT PERCENT OF
TITLE OF OF OF TOTAL VOTING
NAME AND ADDRESS CLASS SHARES CLASS POWER(1)
- ---------------------------------------------------------- -------- ---------- ------- ------------

Blackstone Management Associates III L.L.C.(2)(5)......... Common 27,817,104 98.2% 80.2%
345 Park Avenue
New York, NY 10154

Class F
Occidental Petroleum Corporation(3)(5).................... Common 6,371,010 100.0% 18.4%
10889 Wilshire Boulevard
Los Angeles, California 90024
Marshall A. Cohen(4) ..................................... Common 116,161 * *
Jeffry N. Quinn(4)........................................ Common 30,000 * *
Dennis R. Eichholz(4) .................................... Common 20,000 * *
All directors and executive officers as a group........... Common 166,161 * *

- --------------------------

* Less than 1%.

(1) Represents the percentage of total voting power of all shares of
common stock beneficially owned by the named stockholder.

(2) Blackstone affiliates currently own 25,387,104 shares of common stock
as follows: 20,255,138 shares by Blackstone Capital Partners III
Merchant Banking Fund L.P., 3,608,734 shares by Blackstone Offshore
Capital Partners III L.P. and 1,523,232 shares by Blackstone Family
Investment Partnership III L.P., for each of which Blackstone
Management

Associates III L.L.C., or BMA, is the general partner having voting
and investment power. Messrs. Peter G. Peterson and Stephen A.
Schwarzman are the founding members of BMA and as such may be deemed
to share beneficial ownership of the shares owned by Blackstone. Each
of BMA and Messrs. Peterson and Schwarzman disclaim beneficial
ownership of such shares. Through its various affiliates, Blackstone
also owns warrants representing the right to purchase 2,430,000
shares of Premcor Inc.

(3) Occidental owns 6,101,000 shares of Class F Common Stock of Premcor
Inc. Occidental also owns warrants representing the right to purchase
30,000 shares of our common stock. Occidental has the right to
exchange such shares for 270,000 shares of Class F Common Stock of
Premcor Inc.

(4) Includes the following shares which such persons have, or will within
60 days of March 1, 2002 have, the right to acquire upon the exercise
of stock options: Mr. Cohen - 50,505; Mr. Quinn - 30,000; and Mr.
Eichholz - 20,000. Mr. Cohen's address is Cassels, Brock & Blackwell,
Scotia Plaza, Suite 2200, 40 King Street West, Toronto Ontario,
M5H-3C2 Canada. The address of each of the named executive officers
is Premcor Inc., 8182 Maryland Avenue, St. Louis, Missouri
63105-3721.

(5) David I. Foley, Robert L. Friedman and Richard C. Lappin, all
directors of Premcor Inc., are designees of BMA, which has investment
and voting control over the shares held or controlled by Blackstone
and as such may be deemed to share beneficial ownership of the shares
held or controlled by Blackstone. Stephen I. Chazen, a director of
Premcor Inc., is an executive officer of Occidental and to the extent
he may be deemed to be a control person of Occidental may be deemed to
be a beneficial owner of shares of common stock owned by Occidental.
Each of such persons disclaims beneficial ownership of such shares.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Each of the related party transactions described below was negotiated
on an arm's length basis. We believe that the terms of each such agreement are
as favorable as those we could have obtained from parties not related to us.

OUR RELATIONSHIP WITH BLACKSTONE

The Blackstone Group L.P. is a private investment firm based in New
York, founded in 1985. Its main businesses include private equity investing,
merger and acquisition advisory services, restructuring advisory services,
real estate investing, mezzanine debt investing and asset management.
Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates,
or Blackstone, acquired its interest in Premcor Inc. in November 1997.

In 1999, we paid fees to Blackstone totaling $8.0 million in
connection with the structuring of the heavy oil upgrade project. Affiliates
of Blackstone may in the future receive customary fees for advisory services
rendered to us. Such fees will be negotiated from time to time with the
independent members of our board of directors on an arm's-length basis and
will be based on the services performed and the prevailing fees then charged
by third parties for comparable services.

Blackstone was party to a Capital Contribution Agreement, dated as of
August 19, 1999, with Sabine River Holding, Neches River Holding, PACC, Port
Arthur Finance Corp. and Premcor Inc. Under that agreement, Blackstone made
$109.6 million in capital investments indirectly to Sabine River Holding in
connection with the Port Arthur heavy oil upgrade project.

OUR RELATIONSHIP WITH OCCIDENTAL PETROLEUM CORPORATION

Occidental Petroleum Corporation explores for, develops, produces and
markets crude oil and natural gas and manufactures and markets a variety of
basic chemicals. Occidental acquired its interest in Premcor Inc. in 1995 and
beneficially owns 18.4 % of its common stock. Occidental also acquired an
approximately 10% equity interest in Sabine River Holding pursuant to a
Subscription Agreement, dated as of August 4, 1999, among Occidental, Sabine
River Holding, Neches River Holding and PACC, in connection with the financing
of the Port Arthur heavy oil upgrade project.

Pursuant to a Stockholders' Agreement, dated August 4, 1999, among
Sabine River Holding, Occidental and Premcor Inc., so long as Occidental and any
transferee that acquires more than 50% of the shares of Sabine River Holding
common stock initially held by Occidental together own in the aggregate at least
20% of the shares originally held by Occidental. Occidental, or at Occidental's
election, any transferee, has the right to designate one director to the board
of directors of Sabine River Holding. Premcor Inc. has the right to designate
the remaining directors, and at least one director must be independent. Premcor
Inc. has the right of first refusal on any Sabine River Holding shares held by
Occidental or a transferee of Occidental intended by such holder to be sold to a
third party, subject to the terms of the transfer restrictions agreement and a
common security agreement. If Premcor Inc. transfers its common stock in Sabine
River Holding to a third party, Occidental may require the transferee to
purchase its shares. If Premcor Inc. receives and accepts an offer from a third
party to purchase all of its holdings of Sabine River Holding common stock,
Occidental or any transferee of Occidental must transfer its holdings of Sabine
River Holding common stock, along with the shares issued in connection with any
recapitalization, to the third party, subject to certain conditions as to
representations and warranties delivered in connection with the transfer of
stock. Sabine River Holding may require Occidental to exchange its holdings of
Sabine River Holding common stock for Premcor Inc. common stock, subject to the
terms of the transfer restrictions agreement and a common security agreement.
The transfer restrictions agreement dated as of August 19, 1999, states that
Premcor Inc. may only acquire Occidental's 10% interest in Sabine River Holding
under limited circumstances, as specified in the agreement.

Occidental entered into a Capital Contribution Agreement, dated as of
August 19, 1999, with Sabine River Holding, Neches River Holding, PACC, Port
Arthur Finance Corp. and Premcor Inc. Under that agreement, Occidental made
$12.2 million in capital investments in Sabine River Holding in connection with
the Port Arthur heavy oil upgrade project.

OUR RELATIONSHIP WITH THE PREMCOR REFINING GROUP INC.

In January 2001, the operations of our heavy oil processing facility at
the Port Arthur refinery began. In 1998, our affiliate, PRG, began construction
at its Port Arthur refinery of new coking, hydrocracking, and sulfur removal
units as well as the expansion of the existing crude unit capacity to 250,000
bpd. This heavy oil upgrade project allows the refinery to process primarily
lower-cost, heavy sour crude oil. In the third quarter of 1999, PRG sold a
portion of the work in progress and certain other assets to us. We then financed
and completed the construction of the coking, hydrocracking, and sulfur removal
facilities. PRG completed the expansion of its 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 stages, with the sulfur removal units and
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, and final completion of the
project was achieved on December 28, 2001. PACC entered into certain agreements
with PRG associated with the operations between our coking, hydrocracking, and
sulfur removal facilities and PRG's Port Arthur refinery. A summary of the
agreements is set forth below. For a more detailed discussion of these
agreements, see "Business--Summary of Principal Contracts."

Ancillary Equipment Lease. We lease 100% of PRG's crude/vacuum and
other ancillary units for a 30-year term, and we are billed an operating fee for
these units, which includes turnaround, capital expenditure, fuel, and fixed
operating costs.

Services and Supply Agreement. PRG provides to us a number of services
and supplies needed for operation of our new and leased units. These supplies
and services include managing crude oil purchases and deliveries, operating the
units that are leased by us, managing the processing of the our feedstocks,
managing routine, preventative and major maintenance on both the new and leased
units, supervising and training our employees, and providing utilities and other
support services to us. Also under this agreement, PRG has a right of first
refusal to utilize approximately 20% of the processing capability of our new and
leased units.

Product Purchase Agreement. We sell to PRG all intermediate and
finished products of our new and leased units, which are priced based on
specified formulas designed to reflect fair market pricing of these products.

Ground Lease. We lease from PRG the site at the Port Arthur refinery on
which our new processing units are located.

Activity Under These Agreements. As of December 31, 2001, PACC had an
outstanding receivable from PRG of $25.1 million (December 31, 2000--$50.4
million) and a payable to PRG of $26.9 million (December 31, 2000--$28.0
million) related to ongoing operations. As of December 31, 2001, PACC had a note
payable to PRG of $7.7 million (December 31, 2000--$7.0 million) related to
construction management services of which $4.9 million (December 31, 2000--$4.9
million) was accounted for as a long-term liability and the remainder as a
current liability.

PACC generated $1,877.2 million in 2001 (2000--$100.3 million)
primarily from the sales of finished and intermediate refined products and crude
oil to PRG. PACC incurred $95.7 million in costs of sales in 2001 (2000--$6.2
million). These costs were associated with the purchase of feedstocks and
hydrogen and the incurrence of pipeline tariffs from PRG. PACC recorded
operating expenses of $52.4 million in 2001 (2000--$8.0 million). These
operating expenses related to services provided by PRG and lease operating
expenses under the various agreements between PRG and PACC. There were no
amounts under these agreements in 1999. See Note 12. "Related Party
Transactions" of the Consolidated Financial Statements for more details
concerning our relationship with PRG.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. AND 2. FINANCIAL STATEMENTS

The financial statements filed as a part of the Report on Form 10-K
are listed in the accompanying index to the financial statements. There are no
financial schedules.

3. EXHIBITS

EXHIBIT
NUMBER DESCRIPTION
------ -----------

3.01 Amended and Restated Certificate of Incorporation of
Sabine River Holding Corp. ("Sabine River") and the
Certificate of Amendment thereto dated August 11,
1999 (Incorporated by reference to Exhibit 3.01(b)
filed with Sabine River's Registration Statement on
Form S-4 (Registration No. 333-92871)).

3.02 Amended and Restated By Laws of Sabine River
(Incorporated by reference to Exhibit 3.02(b) filed
with Sabine River's Registration Statement on Form
S-4 (Registration No. 333-92871)).

4.1 Indenture, dated as of August 19, 1999, among Sabine
River, Neches River Holding Corp. ("Neches River"),
Port Arthur Finance Corp. ("PAFC"), Port Arthur Coker
Company L.P. ("PACC"), HSBC Bank USA, as Capital
Markets Trustee, and Bankers Trust Company, as
Collateral Trustee (Incorporated by reference to
Exhibit 4.1 filed with PAFC's Registration Statement on
Form S-4 (Registration No. 333-92871)).

4.2 Form of 12.50% Senior Secured Notes due 2009
(Incorporated by reference to Exhibit 4.2 filed with
PAFC's Registration Statement on Form S-4
(Registration No. 333-92871)).

4.3 Registration Rights Agreement, dated as of August 19,
1999, among Credit Suisse First Boston corporation,
Goldman, Sachs & Co., Deutsche Bank Securities Inc.,
Premcor Inc. (f/k/a Clark Refining Holdings Inc.),
PAFC, PACC, Sabine River and Neches River (Incorporated
by reference to Exhibit 4.03 filed with Sabine River's
Registration Statement on Form S-4 (Registration No.
333-92871)).

4.4 Common Security Agreement, dated as of August 19, 1999,
among PAFC, PACC, Sabine River, Neches River, Bankers
Trust Company, as Collateral Trustee and Depositary
Bank, Deutsche Bank AG, New York Branch ("Deutsche
Bank"), as Administrative Agent, Winterthur
International Insurance Company Limited, an English
company ("Winterthur"), as Oil Payment Insurers
Administrative Agent and HSBC Bank USA, as Capital
Markets Trustee (Incorporated by reference to Exhibit
4.04 filed with PAFC's Registration Statement on Form
S-4 (Registration No. 333-92871)).

EXHIBIT
NUMBER DESCRIPTION
------ -----------

4.5 Transfer Restrictions Agreement, dated as of August 19,
1999, among PAFC, PACC, Premcor Inc. (f/k/a Clark
Refining Holdings Inc.), Sabine River, Neches River,
Blackstone Capital Partners III Merchant Banking Fund
L.P. ("BCP III"), Blackstone Offshore Capital Partners
III L.P. ("BOCP III"), Blackstone Family Investment
Partnership III ("BFIP III"), Winterthur, as the Oil
Payment Insurers Administrative agent, Bankers Trust
Company, as Collateral Trustee, Deutsche Bank, as
Administrative Agent and HSBC Bank USA, as Capital
Markets Trustee (Incorporated by reference to Exhibit
4.05 filed with PAFC's Registration Statement on Form
S-4 (Registration No. 333-92871)).

4.6 Intercreditor Agreement, dated as of August 19, 1999,
among Bankers Trust Company, as collateral Trustee,
Deutsche Bank, as Administrative Agent, Winterthur,
as Oil Payment Insurers Administrative Agent and Debt
Service Reserve Insurer and HSBC Bank, as Capital
Markets Trustee (Incorporated by reference to Exhibit
4.06 filed with Sabine River's Registration Statement
on Form S-4 (Registration No. 333-92871)).

4.7 Stockholders' Agreement, dated as of August 4, 1999,
among Sabine River, Premcor Inc. (f/k/a Clark
Refining Holdings Inc.) and Occidental Petroleum
Corporation (Incorporated by reference to Exhibit
4.18 filed with Premcor Inc.'s Registration Statement
on Form S-1 (Registration No. 333.-70314)).

10.1 Capital Contribution Agreement, dated as of August 19,
1999, among BCP III, BOCP III, BFIP III, Premcor Inc.
(f/k/a Clark Refining Holdings Inc.), PACC, Sabine
River, Neches River and Bankers Trust Company, as
Collateral Trustee (Incorporated by reference to
Exhibit 10.01 filed with PAFC's Registration Statement
on Form S-4 (Registration No. 333-92871)).

10.2 Capital Contribution Agreement, dated as of August 19,
1999, by and among Occidental Petroleum Corporation,
Premcor Inc. (f/k/a Clark Refining Holdings, Inc.),
PACC, Sabine River, Neches River and Bankers Trust
Company, as Collateral Trustee (Incorporated by
reference to Exhibit 10.02 filed with PAFC's
Registration Statement on Form S-4 (Registration No.
333-92871)).

10.3 Bank Senior Loan Agreement, dated as of August 19,
1999, among PAFC, PACC, Sabine River, Neches River,
Deutsche Bank, as Administrative Agent and the Bank
Senior Lenders named therein (Incorporated by reference
to Exhibit 10.03 filed with PAFC's Registration
Statement on Form S-4 (Registration No. 333-92871)).

10.4 Secured Working Capital Facility, dated as of August
19, 1999, among PAFC, PACC, Sabine River, Neches River,
Deutsche Bank, as Administrative Agent, and the Bank
Senior Lenders named therein (Incorporated by reference
to Exhibit 10.04 filed with PAFC's Registration
Statement on Form S-4 (Registration No. 333-92871)).

10.5 Reimbursement Agreement, dated as of August 19, 1999,
among PAFC, PACC, Sabine River, Neches River and
Winterthur, as Primary Insurer and Oil Payment Insurers
Administrative Agent (Incorporated by reference to
Exhibit 10.05 filed with PAFC's Registration Statement
on Form S-4 (Registration No. 333-92871)).

10.6 Engineering, Procurement and Construction Contract,
dated as of July 12, 1999, between PACC and Foster
Wheeler USA Corporation (Incorporated by reference to
Exhibit 10.06 filed with Sabine River's Registration
Statement on Form S-4 (Registration No. 333-92871)).

EXHIBIT
NUMBER DESCRIPTION
------ -----------

10.7 EPC Contract Parent Guarantee, dated as of July 13,
1999, between PACC and Foster Wheeler Corporation
(Incorporated by reference to Exhibit 10.07 filed with
Sabine River's Registration Statement on Form S-4
(Registration No. 333-92871)).

10.8 Services and Supply Agreement, dated as of August 19,
1999, between PACC and The Premcor Refining Group Inc.
("PRG")(f/k/a Clark Refining & Marketing, Inc.)
(Incorporated by reference to Exhibit 10.08 filed with
Sabine River's Registration Statement on Form S-4
(Registration No. 333-92871)).

10.9 Product Purchase Agreement, dated as of August 19,
1999, between PACC and PRG (f/k/a Clark Refining &
Marketing, Inc.) Incorporated by Reference to Exhibit
10.09 filed with Sabine River's Registration Statement
on Form S-4 (Registration No. 333-92871)).

10.10 Hydrogen Supply Agreement, dated as of August 1, 1999,
between PACC and Air Products and Chemicals, Inc.
(Incorporated by Reference to Exhibit 10.10 filed with
PAFC's Registration Statement on Form S-4 (Registration
No. 333-92871)).

10.11 First Amendment, dated March 1, 2000, to the Hydrogen
Supply Agreement, dated as of August 1, 1999, between
PACC and Air Products and Chemicals, Inc. (Incorporated
by reference to Exhibit 10.1 filed with Sabine River's
Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001 (File No. 333-92871)).

10.12 Second Amendment, dated June 1, 2001, to the Hydrogen
Supply Agreement, dated as of August 1, 1999, between
PACC and Air Products and Chemicals, Inc. (Incorporated
by reference to Exhibit 10.2 filed with Sabine River's
Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001 (File No. 333-92871)).

10.13 Coker Complex Ground Lease, dated as of August 19,
1999, between PACC and PRG (f/k/a Clark Refining &
Marketing, Inc.) Incorporated by Reference to Exhibit
10.11 filed with Sabine River's Registration Statement
on Form S-4 (Registration No. 333-92871)).

10.14 Ancillary Equipment Site Lease, dated as of August 19,
1999, between PACC and PRG (f/k/a Clark Refining &
Marketing, Inc.) Incorporated by Reference to Exhibit
10.12 filed with Sabine River's Registration Statement
on Form S-4 (Registration No. 333-92871)).

10.15 Assignment and Assumption Agreement, dated as of August
19, 1999, between PACC and PRG (f/k/a Clark Refining &
Marketing, Inc.) (Incorporated by Reference to Exhibit
10.13 filed with Sabine River's Registration Statement
on Form S-4 (Registration No. 333-92871)).

10.16 Maya Crude Oil Sales Agreement, dated as of March 10,
1998, between PRG (f/k/a Clark Refining & Marketing,
Inc.) and P.M.I. Comercio Internacional, S.A. de C.V.
("PMI"), as assigned by PRG to PACC pursuant to the
Assignment and Assumption Agreement, dated as of August
19, 1999 (Incorporated by Reference to Exhibit 10.14
filed with PACC's Registration Statement on Form S-4
(Registration No. 333-92871)).

EXHIBIT
NUMBER DESCRIPTION
------ -----------

10.17 First Amendment and Supplement to the Maya Crude Oil
Sales Agreement, dated as of August 19, 1999, between
PMI and PACC (Incorporated by Reference to Exhibit
10.15 filed with PAFC's Registration Statement on Form
S-4 (Registration No. 333-92871)).

10.18 Guarantee Agreement, dated as of March 10, 1998,
between PRG (f/k/a Clark Refining & Marketing, Inc.)
and Petroleos Mexicanos, as assigned by PRG to PACC as
of August 19, 1999 pursuant to the Assignment and
Assumption Agreement, dated as of August 19, 1999
(Incorporated by Reference to Exhibit 10.16 filed with
PAFC's Registration Statement on Form S-4 (Registration
No. 333-92871)).

10.19 Premcor 2002 Equity Incentive Plan (filed herewith).

21 Subsidiaries of Sabine River (Incorporated by
Reference to Exhibit 21 filed with Sabine River's
Registration Statement on Form S-4 (Registration No.
333-92871)).

24 Power of Attorney (filed herewith).

(b) REPORTS ON FORM 8-K

We filed the following reports on Form 8-K during the period covered
by this report and up to and including the date of filing of this report:

(1) a report dated April 10, 2001 (announcing that Premcor Inc.,
which owns 90% of our outstanding common stock, had retained Credit
Suisse First Boston and The Blackstone Group L.P. as financial
advisers);

(2) a report dated February 5, 2002 (announcing that Premcor Inc. had
appointed Thomas D. O'Malley Chairman, Chief Executive Officer and
President of Premcor); and

(3) a report dated February 12, 2002 (announcing that Premcor Inc.
had announced its fourth quarter and full year results).

SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS

PAGE

Annual Financial Statements

Independent Auditors' Report............................................ F-2

Consolidated Balance Sheets as of December 31, 2000 and 2001............ F-3

Consolidated Statements of Operations for the period May 4, 1999
(inception) to December 31,1999 and for the years ended
December 31, 2000 and 2001............................................ F-4

Consolidated Statements of Cash Flows for the period May 4, 1999
(inception) to December 31,1999 and for the years ended
December 31, 2000 and 2001............................................ F-5

Consolidated Statements of Stockholders' Equity for the period
May 4, 1999 (inception) to December 31, 1999 and for the years
ended December 31, 2000 and 2001...................................... F-6

Notes To Consolidated Financial Statements.............................. F-7

F-1

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of Sabine River Holding Corp.:

We have audited the accompanying consolidated balance sheets of Sabine
River Holding Corp. and Subsidiaries (the "Company") as of December 31, 2001 and
2000, and the related consolidated statements of operations, stockholders'
equity, and cash flows for the years ended December 31, 2001 and 2000, and for
the period from May 4, 1999 (date of inception) to December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of the Company at December 31,
2001 and 2000, and the results of its operations and its cash flows for the
years ended December 31, 2001 and 2000, and for the period from May 4, 1999
(date of inception) to December 31, 1999, in conformity with accounting
principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

St. Louis, Missouri
February 11, 2002
March 29, 2002 as to Note 8

F-2

SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE DATA)

DECEMBER 31,
----------------------------------------
ASSETS 2000 2001
------------------ -----------------
CURRENT ASSETS:

Cash and cash equivalents........................................... $ 36.4 $ 222.8
Cash and cash equivalents restricted for debt service............... -- 30.8
Receivable from affiliate........................................... 55.0 25.1
Inventories......................................................... 45.3 40.1
Prepaid expenses.................................................... 5.0 11.5
---------- ----------
Total current assets.............................................. 141.7 330.3

PROPERTY, PLANT AND EQUIPMENT, NET..................................... 640.8 632.4
OTHER ASSETS........................................................... 20.2 16.4
---------- ----------
$ 802.7 $ 979.1
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES:
Accounts payable.................................................... $ 84.7 $ 82.3
Accrued expenses and other.......................................... 22.3 20.5
Accrued taxes other than income..................................... 1.4 4.9
Payable to affiliate................................................ 30.1 38.2
Current portion of long-term debt................................... -- 79.6
Current portion of note payable to affiliate........................ 2.1 2.8
---------- ----------
Total current liabilities......................................... 140.6 228.3

LONG-TERM DEBT......................................................... 542.6 463.0

DEFERRED INCOME TAXES.................................................. 0.4 40.6

NOTE PAYABLE TO AFFILIATE.............................................. 4.9 4.9

COMMON STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value per share, 12,000,000 authorized;
6,818,182 shares issued and outstanding........................... 0.1 0.1
Paid-in capital..................................................... 121.7 121.7
Retained earnings (deficit)......................................... (7.6) 120.5
---------- ----------
Total common stockholders' equity................................. 114.2 242.3
---------- ----------
$ 802.7 $ 979.1
========== ==========

The accompanying notes are an integral part of these statements.

F-3

SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN MILLIONS)

FOR THE YEAR ENDED DECEMBER 31,
----------------- ---------------------------------
For the Period
from May 4, 1999
(inception) to
December 31, 1999 2000 2001
----------------- --------------- ---------------

NET SALES AND OPERATING REVENUES FROM AFFILIATES............. $ -- $ 100.3 $ 1,882.4

EXPENSES:
Cost of sales............................................. -- 83.6 1,460.2
Operating expenses........................................ -- 10.2 140.4
General and administrative expenses....................... 3.1 1.1 4.1
Depreciation.............................................. -- -- 20.5
----------- ---------- ----------
3.1 94.9 1,625.2
----------- ---------- ----------

OPERATING INCOME (LOSS)...................................... (3.1) 5.4 257.2

Interest and finance expense.............................. (12.5) (4.0) (66.5)
Interest income........................................... 1.7 0.8 6.4
----------- ---------- ----------

INCOME (LOSS) BEFORE INCOME TAXES............................ (13.9) 2.2 197.1

Income tax (provision) benefit............................ -- 4.1 (69.0)
----------- ---------- ----------

NET INCOME (LOSS)............................................ $ (13.9) $ 6.3 $ 128.1
=========== ========== ==========

The accompanying notes are an integral part of these statements.

F-4

SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN MILLIONS)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................................. $ (13.9) $ 6.3 $ 128.1

Adjustments:
Depreciation...................................................... -- -- 20.5
Amortization of deferred financing costs.......................... 0.5 2.7 3.1
Deferred income taxes............................................. -- 0.4 40.2
Other, net........................................................ -- -- 0.7
Cash provided by (reinvested in) working capital:
Prepaid expenses.................................................. (0.8) (4.2) (6.5)
Inventories....................................................... -- (45.3) 5.2
Accounts payable, accrued expenses, and taxes other than income... 43.3 67.7 (0.7)
Cash and cash equivalents restricted for debt service............. -- -- (24.3)
Affiliate receivables and payables................................ -- (25.3) 38.7
-------- -------- --------
Net cash provided by operating activities....................... 29.1 2.3 205.0
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant, and equipment................... (380.6) (262.4) (12.1)
Cash and cash equivalents restricted for investment in capital
additions....................................................... (46.6) 46.6 --
-------- -------- --------
Net cash used in investing activities........................... (427.2) (215.8) (12.1)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt.......................... 360.0 182.6 --
Proceeds from issuance of common stock............................ 57.1 64.6 --
Cash and cash equivalents restricted for debt repayment........... -- -- (6.5)
Deferred financing costs.......................................... (18.9) (2.3) --
Proceeds from affiliate note payable.............................. -- 4.9 --
-------- -------- --------
Net cash provided by (used in) financing activities............. 398.2 249.8 (6.5)
-------- -------- --------
NET INCREASE IN CASH AND CASH EQUIVALENTS.............................. 0.1 36.3 186.4
CASH AND CASH EQUIVALENTS, beginning of period......................... -- 0.1 36.4
-------- -------- --------
CASH AND CASH EQUIVALENTS, end of period............................... $ 0.1 $ 36.4 $ 222.8
======== ======== ========

The accompanying notes are an integral part of these statements.

F-5

SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(DOLLARS IN MILLIONS)

NUMBER OF
COMMON COMMON PAID-IN RETAINED
SHARES STOCK CAPITAL EARNINGS TOTAL
----------- ---------- ----------- ----------- ----------

Balance at inception............... -- $ -- $ -- $ -- $ --

Equity contributions........... 6,818,182 0.1 57.1 -- 57.2
Net loss....................... -- -- -- (13.9) (13.9)
--------- -------- --------- --------- --------
Balance December 31, 1999.......... 6,818,182 0.1 57.1 (13.9) 43.3

Equity contributions........... -- -- 64.6 -- 64.6
Net income..................... -- -- -- 6.3 6.3
--------- -------- --------- --------- --------
Balance December 31, 2000.......... 6,818,182 0.1 121.7 (7.6) 114.2

Net income..................... -- -- -- 128.1 128.1
--------- -------- --------- --------- --------
Balance December 31, 2001.......... 6,818,182 $ 0.1 $ 121.7 $ 120.5 $ 242.3
========= ======== ========= ========= ========

The accompanying notes are an integral part of these statements.

F-6

SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE PERIOD FROM INCEPTION TO DECEMBER 31, 1999
AND FOR THE YEARS ENDED DECEMBER 31, 2000 AND 2001
(TABULAR AMOUNTS IN MILLIONS OF US DOLLARS)

1. NATURE OF BUSINESS

Sabine River Holding Corp., a Delaware corporation (individually,
"Sabine River" and collectively with its subsidiaries, the "Company ") was
incorporated in May of 1999 and capitalized in August of 1999. Sabine River is a
privately held company with two subsidiaries, Neches River Holding Corp., a
Delaware Corporation ("Neches River") and Port Arthur Coker Company L.P a
Delaware limited partnership ("Port Arthur Coker Company"). Sabine River owns
100% of Neches River and is the 1% general partner of Port Arthur Coker Company.
Neches River is the 99% limited partner of Port Arthur Coker Company. Port
Arthur Coker Company is the 100% owner of Port Arthur Finance Corp. ( "Port
Arthur Finance "). Sabine River is owned 90% by Premcor Inc. and 10% by
Occidental Petroleum Corporation ( "Occidental "). Premcor Inc. is principally
owned by Blackstone Capital Partners III Merchant Banking Fund L.P. and its
affiliates ( "Blackstone ") and by Occidental. The Company is an affiliate of
The Premcor Refining Group Inc. ( "Premcor Refining Group ") since Premcor Inc.
owns 100% of the capital stock of Premcor USA Inc. ( "Premcor USA "), which in
turn owns 100% of the capital stock of Premcor Refining Group.

The Company was formed to develop, construct, own, operate, and finance
a heavy oil processing facility that includes a new 80,000 barrel per stream day
delayed coking unit, a 35,000 barrel per stream day hydrocracker unit, and a 417
long tons per day sulfur complex and related assets at Premcor Refining Group's
Port Arthur Texas refinery. This heavy oil processing facility along with
modifications made by Premcor Refining Group at their Port Arthur refinery
allows the refinery to process primarily lower-cost, heavy sour crude oil.

In January 2001, Port Arthur Coker Company began full operation of the
newly constructed coking, hydrocracking, and sulfur removal units. Premcor
Refining Group began construction of these new units in 1998. In the third
quarter of 1999, Port Arthur Coker Company purchased a portion of the work in
progress and certain other related assets from Premcor Refining Group. The
Company financed and completed the construction of the heavy oil processing
facility. In order to fund the heavy oil processing facility, in August 1999,
Port Arthur Finance issued $255 million of 12 1/2% senior secured notes,
borrowed under a bank senior loan agreement, and obtained a secured working
capital facility, then subsequently remitted the proceeds to Port Arthur Coker
Company. Port Arthur Finance's organizational documents allow it only to engage
in activities related to issuing notes and borrowing under bank credit
facilities in connection with the initial financing of Port Arthur Coker
Company. In issuing the notes and borrowing under the bank credit facilities,
Port Arthur Finance is acting as an agent for Port Arthur Coker Company. As
stand alone entities, both Sabine River's and Neches River's functions consist
only as guarantors of the notes and bank loans issued by Port Arthur Finance.
Sabine River and Neches River, as stand-alone entities, have no material assets,
no liabilities, and no operations.

Start-up of our units occurred in stages, with the sulfur removal units
and the coker unit beginning operations in December 2000 and the hydrocracker
unit beginning operations in January 2001. Substantial reliability, as defined
in our financing documents and construction contract, of the heavy oil
processing facility was achieved as of September 30, 2001. Final completion was
achieved on December 28, 2001.

All of the operations of the Company are in the United States. These
operations are related to the refining of crude oil into petroleum products and
are all considered part of one business segment. The Company's earnings and cash
flows from operations are primarily dependent upon processing crude oil and
selling quantities of refined petroleum products at margins sufficient to cover
operating expenses. Crude oil and refined petroleum products are commodities,
and factors largely out of the Company's control can cause prices to vary, in a
wide range, over a short period of time. This potential margin volatility can
have a material effect on financial position, current period earnings, and cash
flows.

F-7

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Development Stage

The Company completed its development activities and commenced its
planned operations in December 2000. The Company until that time was in the
development stage.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts
of the Company's wholly-owned subsidiary Neches River, and, through Neches
River's 99% limited partnership interest in Port Arthur Coker Company and Sabine
River's 1% general partnership interest in Port Arthur Coker Company, 100% of
Port Arthur Coker Company and Port Arthur Coker Company's wholly owned
subsidiary, Port Arthur Finance.

The Company consolidates the assets, liabilities, and results of
operations of subsidiaries in which the Company has a controlling interest. All
significant intercompany accounts and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities at
the dates of financial statements, and the reported amounts of revenues and
expenses during the reporting periods. Actual results could differ from those
estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments, such as time
deposits, money market instruments, commercial paper and United States and
foreign government securities, purchased with an original maturity of three
months or less, to be cash equivalents.

Revenue Recognition

Revenue from sales of products is recognized upon transfer of title,
based upon the terms of delivery.

Supply and Marketing Activities

The Company engages in the buying and selling of crude oil to supply
its processing capacity at the refinery. Purchases of crude oil are recorded in
"cost of sales". Sales of crude oil where the Company bears risk on market
price, timing, and other non-controllable factors are recorded in "net sales and
operating revenue" otherwise, the sales of crude oil are recorded against "cost
of sales". Crude oil exchange transactions that do not involve the payment or
receipt of cash are not accounted for as purchases or sales. Any resulting
volumetric exchange balances are accounted for as inventory in accordance with
the Company's first-in, first-out ("FIFO") inventory method. Exchanges that are
settled through payment or receipt of cash are accounted for as purchases or
sales.

Inventories

Inventories are stated at the lower of cost or market. Cost is
determined under the FIFO method for hydrocarbon inventories including crude
oil, refined products, and blendstocks. The cost of warehouse stock and other
inventories is determined under the FIFO method. Any reserve for inventory cost
in excess of market value is reversed if physical inventories turn and prices
recover above cost.

F-8

Property, Plant, and Equipment

Property, plant, and equipment additions are recorded at cost.
Depreciation of property, plant, and equipment is computed using the
straight-line method over the estimated useful lives of the assets or group of
assets, beginning for all Company-constructed assets in the month following the
date in which the asset first achieves its design performance. The Company
capitalizes the interest cost associated with major construction projects based
on the effective interest rate on aggregate borrowings.

Expenditures for maintenance and repairs are expensed as incurred.
Expenditures for major replacements and additions are capitalized. Upon disposal
of assets depreciated on an individual basis, gains and losses are reflected in
current operating income. Upon disposal of assets depreciated on a group basis,
unless unusual in nature or amount, residual cost less salvage is charged
against accumulated depreciation.

The Company reviews long-lived assets for impairments whenever events
or changes in circumstances indicate that the carrying amount of an asset may
not be recoverable. If the undiscounted future cash flows of an asset to be held
and used in operations is less than the carrying value, the Company would
recognize a loss for the difference between the carrying value and fair market
value.

Income Taxes

Sabine River and Neches River are included in the consolidated U.S.
federal income tax return filed by Premcor Inc. Sabine River and Neches River
compute their provisions on a separate company basis with adjustments necessary
to reflect the effect of consolidated tax return allocations and limitations.
Deferred taxes are classified as current or noncurrent depending on the
classification of the assets and liabilities to which the temporary differences
relate. Deferred taxes arising from temporary differences that are not related
to a specific asset or liability are classified as current or noncurrent
depending on the periods in which the temporary differences are expected to
reverse. Sabine River and Neches River record a valuation allowance when
necessary to reduce the net deferred tax asset to an amount expected to be
realized.

Port Arthur Coker Company is classified as a partnership for U.S.
federal income tax purposes and, accordingly, does not pay federal income tax.
Port Arthur Coker Company files a U.S. partnership return of income and its
taxable income or loss flows through to its partners who report and are taxed on
their distributive shares of such taxable income or loss. Accordingly, no
federal income taxes have been provided by Port Arthur Coker Company. Port
Arthur Finance files a separate U.S. federal income tax return and computes its
provision on a separate company basis.

New Accounting Standards

In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, and 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. 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 is limited in the hedging strategies that it can enter into
under its debt agreements.

F-9

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 implementation of SFAS No. 141 and SFAS
No. 142 are not expected to have material impact on the Company's 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
implementation of SFAS No. 143 is not expected to have a material impact on the
Company's financial position or results of operations.

In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. This statement addresses financial
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of, and the accounting and reporting
provisions of APB Opinion No. 30, Reporting the Results of Operations--Reporting
the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual
and Infrequently Occurring Events and Transactions, for the disposal of a
segment of a business (as previously defined in that Opinion). The provisions of
this statement are effective for financial statements issued for fiscal years
beginning after December 15, 2001, and interim periods within those fiscal
years, with early application encouraged. The implementation of SFAS No. 144 is
not expected to have a material impact on the Company's financial position or
results of operations.

3. FINANCIAL INSTRUMENTS

Fair Value Financial Instruments

Cash and cash equivalents, accounts receivable and accounts payable
approximate fair value due to the short-term nature of these items. See Note
8--"Long-Term Debt" for disclosure of fair value of long-term debt.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to
concentration of credit risk consist primarily of trade receivables. The
Company's only customer is its affiliate, Premcor Refining Group (see Note
12--"Related Party Transactions"). There were no trade receivable credit losses
for the two years ended December 31, 2001 and the period ended December 31,
1999.

4. INVENTORIES

The carrying value of inventories consisted of the following:

DECEMBER 31,
-----------------------
2000 2001
---------- ----------
Crude oil................................. $ 44.6 $ 38.1
Refined products and blendstocks.......... 0.7 1.6
Warehouse stock........................... -- 0.4
-------- --------
$ 45.3 $ 40.1
======== ========

As of December 31, 2000 and 2001, the carrying value of crude oil,
refined product, and blendstock inventories approximated market value.

F-10

5. PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following:

DECEMBER 31,
----------------------
2000 2001
---------- ----------
Process units, buildings, and oil storage and movement.. $ -- $ 631.5
Construction in progress................................ 640.8 21.4
Accumulated depreciation ............................... -- (20.5)
-------- --------
$ 640.8 $ 632.4
======== ========

The useful life on depreciable assets used to determine depreciation
was 30 years.

6. OTHER ASSETS

Other assets consisted of the following:

DECEMBER 31,
----------------------
2000 2001
---------- ----------
Deferred financing costs................................ $ 18.0 $ 14.2
Environmental permits................................... 1.4 1.4
PEMEX long term crude oil supply agreement.............. 0.8 0.8
-------- --------
$ 20.2 $ 16.4
======== ========

Amortization of deferred financing costs for the year ended December
31, 2001 was $3.1 million (2000--$2.7 million; 1999--$0.5 million) and is
included in "Interest and finance expense." Deferred financing costs are
amortized over the life of the related financial instrument. In 2001, the
Company recorded its interest rate cap on its bank senior loan agreement at fair
market value resulting in the write-down of deferred financing costs of $0.7
million.

7. WORKING CAPITAL FACILITY

Port Arthur Finance has a $35 million working capital facility which is
primarily for the issuance of letters of credit for the purchases of crude oil
other than the Maya crude oil to be received under a long-term crude oil supply
agreement with PMI Comercio Internacional, S.A. de C.V ("PEMEX"), an affiliate
of Petroleos Mexicanos, the Mexican state oil company. As of December 31, 2001,
none of the line of credit was utilized for letters of credit (2000 - $29.3
million).

In order to provide security to PEMEX for Port Arthur Coker Company's
obligation to pay for shipments of Maya crude oil under the long-term crude oil
supply agreement, Port Arthur Coker Company obtained from Winterthur
International Insurance Company Limited ("Winterthur"), an oil payment guaranty
insurance policy for the benefit of PEMEX. This oil payment guaranty insurance
policy is in the amount of $150 million and will be a source of payment to PEMEX
if Port Arthur Coker Company fails to pay PEMEX for one or more shipments of
Maya crude oil. Under the senior debt documents, any payments by Winterthur on
this policy are required to be reimbursed by Port Arthur Coker Company. This
reimbursement obligation to Winterthur has an equal and ratable claim on all of
the collateral for holders of Port Arthur Coker Company's senior debt, except in
specified circumstances in which it has a senior claim to these parties. As of
December 31, 2001, $79.5 million (2000 - $62.1 million) of crude oil purchase
commitments were outstanding related to this policy.

Under senior debt covenants, Port Arthur Coker Company was required to
establish a debt service reserve account and at the time the heavy oil
processing facility achieved substantial reliability, deposit or cause the
deposit of an amount equal to the next semiannual payment of principal and
interest. In lieu of depositing funds into this reserve account at substantial
reliability, Port Arthur Coker Company arranged for Winterthur to provide a
separate debt service reserve insurance policy in the maximum amount of $60
million for a period of approximately five years from substantial reliability of
the heavy oil processing facility. Payments will be made under this policy

F-11

to pay debt service to the extent that Port Arthur Coker Company does not have
sufficient funds available to make a debt service payment on any scheduled
semiannual payment date during the term of the policy. The term of the policy
commenced at substantial reliability of the heavy oil processing facility and
ends on the tenth semiannual payment date after substantial reliability, unless
it terminates early because the debt service reserve account is funded to the
required amount. The maximum liability of Winterthur under its policy is reduced
as Port Arthur Coker Company makes deposits into the debt service reserve
account. On the sixth semiannual payment date after substantial reliability, and
on each of the next four semiannual payment dates, Port Arthur Coker Company is
required to deposit, out of available funds for that purpose, $12 million into
the debt service reserve account. Under a secured account structure (See Note
8--"Long-Term Debt"), until the debt service reserve account contains the
required amount, Port Arthur Coker Company is required to make deposits into the
debt service reserve account equal to all of Port Arthur Coker Company's excess
cash flow that remains after Port Arthur Coker Company applies 75% of excess
cash flow to prepay the bank senior loan agreement. Once the debt service
reserve account contains the required amount, the Winterthur policy will
terminate.

8. LONG-TERM DEBT

DECEMBER 31,
----------------------
2000 2001
---------- ----------
12 1/2% Senior Secured Notes due January 15, 2009
("12 1/2% Senior Notes").......................... $ 255.0 $ 255.0
Bank Senior Loan Agreement............................. 287.6 287.6
-------- --------
542.6 542.6
Less current portion................................... -- 79.6
------- --------
$ 542.6 $ 463.0
======== ========

The estimated fair value of long-term debt as of December 31, 2001 was
$546.4 million (2000--$530.0 million), determined using quoted market prices as
applicable.

The 12 1/2% Senior Notes were issued by Port Arthur Finance in August
1999 on behalf of Port Arthur Coker Company at par and are secured by
substantially all of the assets of the Company. The 12 1/2% Senior Notes are
redeemable at the Company's option at any time at a redemption price equal to
100% of principal plus accrued and unpaid interest plus a make-whole premium
which is based on the rates of treasury securities with average lives comparable
to the average life of the remaining scheduled payments plus 0.75%.

In August 1999, Port Arthur Finance entered into a bank senior loan
agreement provided by commercial banks and institutional lenders. The Company
had access to $325 million under the bank senior loan agreement, of which it
drew $287.6 million as of December 31, 2001. The bank senior loan agreement is
split into a Tranche A of $106.5 million with a term of 7 1/2 years and a
Tranche B of $181.1 million with a term of 8 years. The interest rates on the
bank senior loan agreement are based on LIBOR plus 4 3/4% for Tranche A and on
LIBOR plus 5 1/4% for Tranche B. The ability to draw the unused portion of the
loan expired in September 2001 when the heavy oil processing facility achieved
substantial reliability. As required under the Port Arthur Finance indentures,
Port Arthur Coker Company entered into a transaction in April 2000 for $0.9
million that capped LIBOR at 7 1/2 % for a varying portion of the principal
outstanding of their bank senior loan agreement. As of December 31, 2001, this
cap had a current market value of under $0.1 million. The cap is for a term from
April 2000 through January 2004.

Under a common security agreement governing the Port Arthur Finance
debt, which contains common covenants, representations, defaults and other terms
with respect to the 12 1/2% Senior Notes, the bank senior loan agreement and the
guarantees thereof by Port Arthur Coker Company, Sabine River, and Neches River,
Port Arthur Coker Company is subject to restrictions on the making of
distributions to Sabine River and Neches River. The common security agreement
contains provisions that require the Company to maintain a secured account
structure that reserves cash balances to be used for operations, capital
expenditures, tax payments, major maintenance, interest, and debt repayments.
This secured account structure must be funded and paid before Port Arthur Coker
Company can make any restricted payments including dividends, except for
$100,000 in distributions to Sabine River and Neches River each year to permit
them to pay directors' fees, accounting expenses, and other

F-12

administrative expenses. In January 2002, Port Arthur Coker Company made a $59.7
million prepayment of its bank senior loan agreement pursuant to the common
security agreement and secured account structure.

The common security agreement also requires that the Company carry
insurance coverage with specified terms. However, due to the effects of the
events of September 11, 2001 on the insurance market, coverage meeting such
terms, particularly as it relates to deductibles, waiting periods and
exclusions, was not available on commercially reasonable terms and, as a result,
the Company's insurance program was not in full compliance with the required
insurance coverage at December 31, 2001. However, the requisite parties to the
common security agreement have waived the noncompliance provided that the
Company obtain a reduced deductible limit for property damage by April 19, 2002,
obtain additional contingent business interruption insurance by June 26, 2002
and continue to monitor the insurance market on a quarterly basis to determine
if additional insurance coverage required by the common security agreement is
available on commercially reasonable terms, and if so, promptly obtain such
insurance. The Company believes that it will be able to comply with all of the
conditions of the waiver.

The scheduled maturities of long-term debt during the next five years
are (in millions); 2002 - $79.6; 2003 - $32.1; 2004 - $47.4; 2005 - $66.0; 2006
- - $54.4; 2007 and thereafter--$263.1.

Interest and finance expense

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

FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
1999 2000 2001
---------- ---------- ----------
Interest expense......... $ 15.6 $ 56.1 60.2
Finance costs............ 10.7 4.0 7.3
Capitalized interest..... (13.8) (56.1) (1.0)
-------- -------- --------
$ 12.5 $ 4.0 $ 66.5
========= ========= ========

Cash paid for interest expense in 2001 was $61.8 million (2000--$49.0
million; 1999--$0.9 million).

9. PORT ARTHUR COKER COMPANY CONDENSED CONSOLIDATED FINANCIAL INFORMATION

Sabine River directly owns a 1% general partnership interest in Port
Arthur Coker Company and through its wholly-owned subsidiary, Neches River, owns
the remaining 99% limited partnership interest. Port Arthur Finance, which is
wholly owned by Port Arthur Coker Company, issued debt on Port Arthur Coker
Company's behalf. Both Sabine River and Neches River fully and unconditionally
guarantee the debt issued by Port Arthur Finance. Port Arthur Coker Company is
the only company with operations in the consolidated financial statements of the
Company. Neither Neches River nor Port Arthur Finance have independent
operations.

F-13

Port Arthur Coker Company's condensed consolidated financial
information consisted of the following:

Consolidated statement of operations:

FOR THE YEAR ENDED
DECEMBER 31,
-------------------------------------
1999 2000 2001
---------- ---------- -----------

Revenues................................ $ -- $ 100.3 $ 1,882.4
Cost of goods sold...................... -- 83.6 1,460.2
Operating expenses...................... -- 10.2 140.4
General and administrative.............. 3.1 1.1 4.0
Depreciation............................ -- -- 20.5
--------- --------- ----------
Operating income........................ (3.1) 5.4 257.3
Interest and finance expense............ (12.5) (4.0) (66.5)
Interest income......................... 1.7 0.8 6.4
-------- -------- ----------
Net income...................... $ (13.9) $ 2.2 $ 197.2
======== ======== ==========

Consolidated balance sheet information:

DECEMBER 31,
---------------------------
2000 2001
----------- ----------
Total current assets.................... $ 137.1 $ 330.4
Property, plant and equipment........... 640.8 632.4
Other assets............................ 20.2 16.4
--------- ---------
Total assets............................ $ 798.1 $ 979.2
========= =========
Total current liabilities............... $ 140.5 217.0
Long-term debt.......................... 542.6 463.0
Note payable to affiliates.............. 4.9 4.9
Partners' capital contributed........... 121.8 108.8
Retained earnings (deficit)............. (11.7) 185.5
--------- ---------
Total liabilities and partners' capital. $ 798.1 $ 979.2
========= =========

10. OPERATING LEASE COMMITMENTS

Under an ancillary equipment lease agreement, Port Arthur Coker Company
leases from Premcor Refining Group 100% of its crude/vacuum unit and distillate
and naphtha hydrotreaters under a 30-year term. Port Arthur Coker Company also
pays an operating fee for these units, which includes fees for turnaround and
sustaining capital accrual, fuel and fixed operating costs. As of December 31,
2001, future minimum lease payments under non-cancelable operating leases were
as follows (in millions): 2002--$33.2; 2003--$33.2; 2004--$33.2; 2005--$33.2;
2006--$33.2; 2007 and thereafter $664.0. Rent expense during 2001 was $32.4
million (2000--$2.8 million).

11. STOCKHOLDERS' EQUITY

In August 1999, Blackstone and Occidental signed capital contribution
agreements totaling $135.0 million for the purpose of funding the construction
of the heavy oil processing facility. Blackstone agreed to contribute $121.5
million and Occidental agreed to contribute $13.5 million. As of December 31,
2001, Blackstone had contributed $109.6 million and Occidental had contributed
$12.2 million. The obligation to fund the capital contributions was contingent
upon the Company borrowing funds under the bank senior loan agreement. In the
third quarter of 2001, the Company decided not to borrow the remaining loan
commitment under the bank senior loan agreement, and consequently, forfeited the
remaining capital contributions. Accordingly, the remaining unfunded capital
contributions of $13.2 million are no longer recorded as a capital contribution
receivable. The ability to draw any remaining funds under the bank senior loan
agreement and receive the remaining capital contributions expired

F-14

in September of 2001 upon the achievement of substantial reliability of the
heavy oil upgrade facility, as defined for purposes of the financing documents.

In August 1999, Sabine River issued warrants to Occidental to purchase
30,000 shares of Sabine River's common stock at a price of $0.09 per share. The
warrants may be exercised at any time in whole or part. Upon exercise of these
warrants, Occidental has the option to exchange each warrant share for nine
shares of Premcor Inc.'s Class F Common Stock. None of the warrants were
exercised as of December 31, 2001.

12. RELATED PARTY TRANSACTIONS

Related party transactions that are not discussed elsewhere in the
footnotes are discussed below:

Premcor Refining Group

In January 2001, the operations of the heavy oil processing facility at
the Port Arthur refinery began. In 1998, the Company's affiliate, Premcor
Refining Group, began construction at its Port Arthur refinery of a new coking,
hydrocracking, and sulfur removal units as well as the expansion of the existing
crude unit capacity to 250,000 barrels per day ("bpd"). The heavy oil upgrade
project allows the refinery to process primarily lower-cost, heavy sour crude
oil. In the third quarter of 1999, Premcor Refining Group sold a portion of the
work in progress and certain other assets to the Company. The Company then
financed and completed the construction of the coking, hydrocracking, and sulfur
removal facilities. Premcor Refining Group completed the expansion of its 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 stages,
with the sulfur removal units and 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, and final completion of the project was achieved on December 28, 2001.

The Company and Premcor Refining Group entered into certain agreements
associated with the operations between its coking, hydrocracking, and sulfur
removal facilities and Premcor Refining Group's Port Arthur refinery. A summary
of the related party agreements between the Company and Premcor Refining Group
is as follows:

Ancillary Equipment Lease. Pursuant to an ancillary equipment lease,
Port Arthur Coker Company leases from Premcor Refining Group 100% of its crude
and vacuum units, and distillate, kerosene and naphtha hydrotreaters. In
addition, under this agreement, the Port Arthur Coker Company pays operating
fees for these units, which includes turnaround, capital expenditure, fuel, and
fixed operating costs. Other costs include utilities and environmental services,
which include items such as nitrogen, demineralized water and other services.
These other costs are in line with market rates and are relatively minor in
proportion to other expenses. Under this agreement, Port Arthur Coker Company
began paying Premcor Refining Group quarterly lease payments in the fourth
quarter of 2000 of approximately $8 million, adjusted for inflation, through the
lease term. The quarterly lease fee is based on a capital recovery charge for
both existing asset values and cost associated with the completion of the
processing facility. The initial term of the ancillary equipment lease is 30
years, with an allowance for five 5-year extensions. The rent for any extension
period will be based on a fair market rental value as agreed to between the Port
Arthur Coker Company and Premcor Refining Group or by a value determined
according to the defined appraisal procedure contained in the agreement
definitions.

Services and Supply Agreement. Pursuant to a services and supply
agreement, Port Arthur Coker Company receives a number of services and supplies
from Premcor Refining Group needed for operation of their new and leased units.
Premcor Refining Group is required to provide all such services and supplies in
accordance with specified standards, including prudent industry practices. These
supplies and services include managing crude oil purchases and deliveries,
operating the units that are leased by Port Arthur Coker Company, managing the
processing of the Port Arthur Coker Company feedstocks, managing routine,
preventative and major maintenance on both Port Arthur Coker Company's assets
and leased units, supervising and training Port Arthur Coker Company employees,
and providing utilities and other support services to Port Arthur Coker Company.
Also under this agreement, Premcor Refining Group has the right of first
refusal, which it may exercise quarterly, to utilize approximately 20% of the
processing capability of the Port Arthur Coker Company new units and the leased
units.

F-15

Product Purchase Agreement. Pursuant to a product purchase agreement,
Port Arthur Coker Company will receive payment from Premcor Refining Group for
all intermediate and finished products of Port Arthur Coker Company's new and
leased units that are tendered for delivery. This payment is subject to Premcor
Refining Group's right as Port Arthur Coker Company's sole customer to request
that Port Arthur Coker Company's new and leased units produce a certain mix of
products. This right, however, is subject to specified limitations that are
designed to ensure that Port Arthur Coker Company utilizes the entire amount of
Maya available to it under its long-term crude oil supply agreement or an
equivalent amount from an alternative supplier. These limitations also ensure
that the operations of the Port Arthur refinery are optimized in a manner that
is mutually beneficial to Port Arthur Coker Company and Premcor Refining Group
and that does not benefit Premcor Refining Group at Port Arthur Coker Company's
expense. Amounts due and receivable under this agreement may not be offset with
amounts otherwise due and receivable from Premcor Refining Group.

Port Arthur Coker Company's new and leased units produce a variety of
products, some of which are readily saleable on the open market, including
finished refined products such as petroleum coke and sulfur, and some of which
are intermediate refined products, including products such as gas oils,
unfinished naphthas, and unfinished jet fuel. The Port Arthur Coker Company
sells these products to Premcor Refining Group for immediate resale in the case
of finished refined products, or for further processing into higher-valued
products in the case of intermediate refined products. Premcor Refining Group
may sell excess intermediate refined products if the supply of these products
exceeds its needs because of refinery unit shutdowns or temporary reduced
capacity.

The product purchase agreement includes pricing formulas for each of
the products produced by Port Arthur Coker Company's new and leased units. These
formulas are intended to reflect fair market pricing of these products and are
used to determine the amounts receivable by Port Arthur Coker Company from
Premcor Refining Group. Many of the intermediate refined products do not have a
widely quoted market price. As a result, formulas for these products are based
on widely quoted product prices of other refined products from sources such as
Platt's Oilgram Price Report, Oil Pricing Information Service or Dynergy or is
calculated based on the weighted average of delivered cost of natural gas
delivered to Premcor Refining Group. To the extent, however, that any of Port
Arthur Coker Company's products are sold to Premcor Refining Group and
immediately resold to a non-affiliated third party, the price receivable by the
Port Arthur Coker Company from Premcor Refining Group for such product is the
purchase price received by Premcor Refining Group from such third party, whether
higher or lower than the formula price, less a specified marketing fee. While
market prices for these commodities fluctuate throughout each day and the
pricing formulas are based on average daily prices, both companies expect that
the price paid by any third party purchaser of these products would be
substantially the same as that paid by Premcor Refining Group in the same
circumstances. An independent engineer has reviewed these formulas and found
that the pricing reflects arm's-length mechanisms and market-based prices and
contain fair market terms. The marketing fee is intended to be consistent with a
fair market fee that would be charged by an unaffiliated third party. The cost
of marketing these products outside of this product purchase agreement would be
incurred whether Port Arthur Coker Company sold the products directly or paid
Premcor Refining Group or another third party to do so on its behalf. Premcor
Refining Group's failure to perform under the product purchase agreement would
give Port Arthur Coker Company a cause of action for resulting damages to Port
Arthur Coker Company.

Ground Lease. Under this lease, the Port Arthur Coker Company is
leasing sites from Premcor Refining Group within the Port Arthur refinery on
which their new processing units are located. The initial term of the ground
lease is 30 years and it may be renewed for five additional five-year terms. The
lease fee of $25,000 was prepaid by Port Arthur Coker Company.

Activity Under These Agreements. As of December 31, 2001, Port Arthur
Coker Company had an outstanding receivable from Premcor Refining Group of $25.1
million (December 31, 2000--$50.4 million) and a payable to Premcor Refining
Group of $26.9 million (December 31, 2000--$28.0 million) related to ongoing
operations. As of December 31, 2001, Port Arthur Coker Company had a note
payable to Premcor Refining Group of $7.7 million (December 31, 2000--$7.0
million) related to construction management services of which $4.9 million
(December 31, 2000- $4.9 million) was accounted for as a long-term liability and
the remainder as a current liability.

Port Arthur Coker Company generated $1,877.2 million in 2001
(2000--$100.3 million) primarily from the sales of finished and intermediate
refined products and crude oil to Premcor Refining Group. Port Arthur Coker

F-16

Company incurred $95.7 million in costs of sales in 2001 (2000--$6.2 million).
These costs were associated with the purchase of feedstocks and hydrogen and the
incurrence of pipeline tariffs from Premcor Refining Group. Port Arthur Coker
Company recorded operating expenses of $52.4 million in 2001 (2000--$8.0
million). These operating expenses related to services provided by Premcor
Refining Group and lease operating expenses under the various agreements between
Premcor Refining Group and Port Arthur Coker Company. There were no amounts
under these agreements in 1999.

Blackstone

In 1999, the Company paid $8.0 million in advisory fees to an affiliate
of Blackstone in connection with the structuring and construction of the heavy
oil processing facility. The affiliates may in the future receive customary fees
for advisory services rendered to the Company. Such fees will be negotiated from
time to time with the independent members of the Company's board of directors
and will be based on the services performed and the prevailing fees then charged
by third parties for comparable services.

13. EMPLOYEE BENEFIT PLANS

Postretirement Benefits Other Than Pensions

The Company's employees are enrolled under Premcor Refining Group's
health care coverage plans for both the active and retired employees. Under this
plan, the Company provides health insurance in excess of social security and an
employee paid deductible amount, and life insurance to most retirees once they
have reached a specified age and specified years of service. The Company
reimburses Premcor Refining Group for expenses incurred on the Company's behalf.

Employee Savings Plan

The employees of the Company participate in the Premcor Retirement
Savings Plan and separate trust (the "Plan"). Under terms of the Plan, a defined
contribution plan, the Company matches the amount of employee contributions,
subject to specified limits. Company contributions to the Plan during 2001 were
$0.4 million (2000--$0.1 million).

14. INCOME TAXES

The Company provides for deferred taxes under the asset and liability
approach, which requires the recognition of deferred tax assets and liabilities
for the expected future tax consequences of temporary differences between the
carrying amounts and the tax bases of assets and liabilities.

The income tax provision (benefit) is summarized as follows:

1999 2000 2001
--------- --------- ----------

Income (loss) before income taxes.............. $ (13.9) $ 2.2 $ 197.1
========= ========== ==========
Income tax provision (benefit):
Current provision (benefit) - Federal........ $ -- $ (4.5) $ 28.8
- State.......... -- -- --
--------- ---------- ----------
-- (4.5) 28.8
--------- ---------- ----------
Deferred provision (benefit) - Federal......... -- 0.4 40.2
- State........... -- -- --
--------- ---------- ----------
-- 0.4 40.2
--------- ---------- ----------
Income tax provision (benefit)................. $ -- $ (4.1) $ 69.0
========= ========== ==========

F-17

A reconciliation between the income tax provision (benefit) computed on
pretax income at the statutory federal rate and the actual provision (benefit)
for income taxes is as follows:

1999 2000 2001
--------- ---------- ---------

Federal taxes computed at 35%............ $ (4.9) $ 0.8 $ 69.0
Valuation allowance...................... 4.9 (4.9) --
--------- --------- ---------
Income tax provision (benefit)........... $ -- $ (4.1) $ 69.0
========= ========= =========

The following represents the approximate tax effect of each significant
temporary difference giving rise to deferred tax liabilities and assets:

DECEMBER 31,
------------------------
2000 2001
--------- ---------
Deferred tax liabilities:
Property, plant and equipment.......... $ 5.6 $ 48.9
Start-up costs......................... 0.7 1.3
Other.................................. -- 2.5
-------- ---------
$ 6.3 $ 52.7
--------- ---------
Deferred tax assets:
Alternative minimum tax credit......... $ 1.2 $ --
Tax loss carryforwards................. 0.7 8.4
Organizational costs................... 0.8 0.6
Working capital costs.................. 3.2 3.1
-------- ---------
5.9 12.1
--------- ---------
Net deferred tax asset (liability)............. $ (0.4) $ (40.6)
========= =========

As of December 31, 2001, the Company had a federal net operating loss
carryforward of $24.0 million. Such operating losses have carryover periods of
20 years and are available to reduce future tax liabilities through the year
ending December 31, 2020. The net operating loss carryover periods will begin to
terminate with the year ending December 31, 2019.

The Company provides for its portion of consolidated refunds and
liability under its tax sharing agreement with Premcor Inc. As of December 31,
2001, the Company had an amount due to Premcor Inc. of $11.3 million related to
income taxes payable. During 2001, the Company made no net state cash payments
and received no net state cash refunds. During 2001, the Company made a net cash
federal income tax payment of $13.0 million (2000 - none).

15. COMMITMENTS AND CONTINGENCIES

Environmental Product Standards

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 the Port Arthur refinery including the
Company's heavy oil processing facility as a result of the Tier 2 standards.
Based on the Company's current estimates, it believes that compliance with the
new Tier 2 gasoline specifications will require capital expenditures in the
aggregate through 2005 of approximately one million dollars for the heavy oil
processing facility.

F-18

Low Sulfur Diesel Standards. 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. The Company estimates its capital expenditures in the
aggregate through 2006 required to comply with the diesel standards, utilizing
existing technologies is approximately $110 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. The Company has
initiated a project at their Port Arthur refinery to comply with these new
diesel fuel specifications in conjunction with an expansion of this refinery to
300,000 bpd.

Long-Term Crude Oil Contract

Port Arthur Coker Company is party to a long-term crude oil supply
agreement with PEMEX which supplies approximately 160,000 barrels per day of
Maya crude oil. Under the terms of this agreement, Port Arthur Coker Company is
obligated to buy Maya crude oil from PEMEX, and PEMEX is obligated to sell to
Port Arthur Coker Company Maya crude oil. An important feature of this agreement
is a price adjustment mechanism designed to minimize the effect of adverse
refining margin cycles and to moderate the fluctuations of the coker gross
margin, a benchmark measure of the value of coker production over the cost of
coker feedstocks. This price adjustment mechanism contains a formula that
represents an approximation of the coker gross margin and provides for a minimum
average coker margin of $15 per barrel over the first eight years of the
agreement, which began on April 1, 2001. The agreement expires in 2011.

On a monthly basis, the actual coker gross margin is calculated and
compared to the minimum. Coker gross margins exceeding the minimum are
considered a "surplus" while coker gross margins that fall short of the minimum
are considered a "shortfall." On a quarterly basis, the surplus and shortfall
determinations since the beginning of the contract are aggregated. Pricing
adjustments to the crude oil the Company purchases are only made when there
exists a cumulative shortfall. When this quarterly aggregation first reveals
that a cumulative shortfall exists, the Company receives a discount on our crude
oil purchases in the next quarter in the amount of the cumulative shortfall. If
thereafter, the cumulative shortfall incrementally increases, the company
receives additional discounts on our crude oil purchases in the succeeding
quarter equal to the incremental increase, and conversely, if thereafter, the
cumulative shortfall incrementally decreases, the Company repays discounts
previously received, or a premium, on our crude oil purchases in the succeeding
quarter equal to the incremental decrease. Cash crude oil discounts received by
the Company in any one quarter are limited to $30 million, while the Company's
repayment of previous crude oil discounts, or premiums, are limited to $20
million in any one quarter. Any amounts subject to the quarterly payment
limitations are carried forward and applied in subsequent quarters.

As of December 31, 2001, as a result of the favorable market conditions
related to the value of Maya crude oil versus the refined products derived from
it, a cumulative quarterly surplus of $110.0 million existed under the contract.
As a result, to the extent the Company experiences quarterly shortfalls in coker
gross margins going forward, the price it pays for Maya crude oil in succeeding
quarters will not be discounted until this cumulative surplus is offset by
future shortfalls.

F-19

SIGNATURES

PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.

SABINE RIVER HOLDING CORP.
(Registrant)

By: /s/ Dennis R. Eichholz
-----------------------------------------------
Dennis R. Eichholz
Senior Vice President - Finance and
Controller (principal accounting officer)

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES INDICATED ON MARCH 20, 2002

SIGNATURE TITLE DATE
--------- ----- ----

* Chairman of the Board, President and Chief
- ------------------------------------- Executive Officer
Thomas D. O'Malley (principal executive officer) March 29, 2002
--------------

/s/ William E. Hantke
- -------------------------------------
William E. Hantke Executive Vice President and Chief Financial March 29, 2002
Officer (principal financial officer) --------------

/s/ Dennis R. Eichholz
- -------------------------------------
Dennis R. Eichholz Senior Vice President - Finance and Controller March 29, 2002
(principal accounting officer) --------------

*
- -------------------------------------
Stephen I. Chazen Director March 29, 2002
--------------

*
- -------------------------------------
David I. Foley Director March 29, 2002
--------------

*
- -------------------------------------
Robert L. Friedman Director March 29, 2002
--------------

*
- -------------------------------------
William E. Haynes Director March 29, 2002
--------------

*By: /s/ Jeffry N. Quinn
- -------------------------------------
Jeffry N. Quinn
Attorney-in-Fact

ORIGINAL POWERS OF ATTORNEY AUTHORIZING WILLIAM E. HANTKE AND JEFFRY
N. QUINN, AND EACH OF THEM, TO SIGN THIS ANNUAL REPORT ON FORM 10-K AND
AMENDMENTS THERETO ON BEHALF OF THE ABOVE-NAMED PERSONS HAVE BEEN FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION AS EXHIBIT 24 TO THIS REPORT.