<PAGE>
As filed with the Securities and Exchange Commission on April 4, 2000.
Registration No. 333-92871
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
Amendment No. 2
To
Form S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
---------------
PORT ARTHUR FINANCE PORT ARTHUR COKER SABINE RIVER NECHES RIVER
CORP. COMPANY L.P. HOLDING CORP. HOLDING CORP.
(Exact Name of (Exact Name of (Exact Name of (Exact Name of
Registrant Issuer Registrant Registrant Parent Registrant
as Specified in Its Guarantor as Guarantor as Guarantor as
Charter) Specified in Its Specified in Its Specified in Its
Charter) Charter) Charter)
DELAWARE DELAWARE DELAWARE
DELAWARE (State or other (State or other (State or other
(State or other jurisdiction of jurisdiction of jurisdiction of
jurisdiction of incorporation or incorporation or incorporation or
incorporation or organization) organization) organization)
organization) 6411 6411 6411
6411 (Primary Standard (Primary Standard (Primary Standard
(Primary Standard Industrial Industrial Industrial
Industrial Classification Code Classification Code Classification Code
Classification Code Number) Number) Number)
Number) 43-1857413 43-1857408 43-1857411
36-4308506 (I.R.S. Employer (I.R.S. Employer (I.R.S. Employer
(I.R.S. Employer Identification Identification Identification
Identification Number) Number) Number)
Number)
---------------
Ken W. Isom
1801 S. Gulfway Drive
Office No. 36
Port Arthur, Texas 77640
(409) 982-7491
(Address, including zip code, and telephone number, including area code, of
registrant issuer's and registrant parent guarantor's principal executive
offices)
(Name, address, including zip code, andtelephone number, including area code,
of agent for service)
---------------
With a copy to: Edward P. Tolley III, Esq. Simpson Thacher & Bartlett 425
Lexington Avenue New York, New York 10017 (212) 455-2000
---------------
Approximate date of commencement of proposed sale to the public: As soon as
practicable after this Registration Statement becomes effective.
If the securities being registered on this form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. [_]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act Registration number of the earlier effective
Registration Statement for the same offering. [_]
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities
Registration Statement number of the earlier effective Registration Statement
for the same offering. [_]
---------------
The Registrants hereby amend this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrants
shall file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933, as amended, or until this Registration Statement
shall become effective on such date as the Commission, acting pursuant to said
Section 8(a), may determine.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+The information in this prospectus is not complete and may be changed. We may +
+not sell these securities until the registration statement filed with the +
+Securities and Exchange Commission is effective. This prospectus is not an +
+offer to sell these securities and it is not soliciting an offer to buy these +
+securities in any state where the offer or sale is not permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Subject to completion dated April 4, 2000
Prospectus
[LOGO OF PORT ARTHUR COKER COMPANY]
$255,000,000
Port Arthur Finance Corp.
Offer to Exchange All Outstanding 12.50% Senior Secured Notes due 2009 for
12.50% Senior Secured Notes due 2009, which have been registered under the
Securities Act of 1933
Unconditionally Guaranteed Jointly and Severally by Port Arthur Coker Company
L.P., Sabine River Holding Corp. and Neches River Holding Corp.
The Exchange Offer The Exchange Notes
. Port Arthur Finance Corp. . The terms of the exchange
will exchange all notes to be issued in the
outstanding notes that are exchange offer are
validly tendered and not substantially identical
validly withdrawn for an to the outstanding notes,
equal principal amount of expect that the exchange
exchange notes that are notes will be freely
freely tradeable. tradeable.
. You may withdraw tenders
of outstanding notes at
any time prior to the
expiration of the exchange
offer.
. The exchange offer expires
at 5:00 p.m., New York
City time, on , 2000,
unless extended. We do not
currently intend to extend
the expiration date.
You should consider carefully the risk factors beginning on page 16 of this
prospectus before participating in the exchange offer.
------------
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
------------
The date of this prospectus is , 2000.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary.................. 1
Risk Factors........................ 16
Use of Proceeds..................... 26
Financing Plan...................... 27
Capitalization...................... 30
Selected Financial Information...... 31
Management's Discussion and Analysis
of Financial Condition............. 33
The U.S. Petroleum Refining Industry
and Refinery Configuration......... 38
Existing Port Arthur Refinery and
The Refinery Upgrade Project....... 42
Coker Gross Margin Support Mechanism
in Our Long Term Crude Oil Supply
Agreement.......................... 44
Our Coker Project................... 46
Independent Engineer's Report
Summary............................ 55
Crude Oil and Refined Product Market
Report Summary..................... 59
Security Ownership of Owners........ 62
Ownership Structure and Related
Party Transactions................. 63
Principal Project Participants...... 66
Management.......................... 69
</TABLE>
<TABLE>
<CAPTION>
Page
----
<S> <C>
Description of Our Principal
Project Documents.............. 71
The Exchange Offer.............. 110
Description of the Notes........ 120
Description of Our Principal
Financing Documents............ 125
Book-Entry; Delivery and Form... 154
Special Legal Aspects........... 155
U.S. Federal Income Tax
Consequences of the Exchange
Offer.......................... 156
Plan of Distribution............ 157
Legal Matters................... 158
Experts......................... 158
Independent Engineer............ 159
Independent Market Consultant... 159
Available Information........... 159
Glossary of Technical Terms..... 160
Index to Financial Statements... F-1
Annex A-Additional Information
Regarding Clark Refining &
Marketing...................... A-1
Annex B-Independent Engineer's
Report......................... B-1
Annex C-Crude Oil and Refined
Product Market Report.......... C-1
</TABLE>
------------
You should rely only on the information contained in this document or to
which we have referred you. We have not authorized anyone to provide you with
information that is different from that contained in this document. This
document may be used only where it is legal to sell these securities. The
information in this document may be accurate only on the date of this document.
i
<PAGE>
PROSPECTUS SUMMARY
In this prospectus, Port Arthur Coker Company L.P. and Port Arthur Finance
Corp. are referred to collectively as "we," "our," "ours" and "us" unless the
reference is specifically to Port Arthur Coker Company L.P. or Port Arthur
Finance Corp.
The following summary highlights information contained elsewhere in this
document. It does not contain all of the information you should consider before
investing in the notes. You should read this entire prospectus carefully.
Overview
Port Arthur Coker Company was formed as a Delaware limited partnership in May
1999 to develop, construct, own, operate and finance a new 80,000 barrel per
stream day delayed coking unit, a 35,000 barrel per stream day hydrocracker and
a 417 long tons per day sulfur complex and related assets currently under
construction at the Port Arthur, Texas refinery of our affiliate Clark Refining
& Marketing, Inc. In this prospectus, we refer to this equipment, collectively
with all of its associated contracts and infrastructure, as our coker project.
Our coker project is part of a coordinated project with Clark Refining &
Marketing and Air Products and Chemicals, Inc. We refer to these coordinated
projects collectively in this prospectus as the refinery upgrade project. The
Clark Refining & Marketing portion of the refinery upgrade project includes
modifications to their crude unit and hydrotreaters. Clark Refining & Marketing
will lease these units to us. In this prospectus, we refer to these leased
units, together with our coker project, as our heavy oil processing facility.
The Air Products portion of the refinery upgrade project consists of a new
hydrogen supply plant that will supply hydrogen for our heavy oil processing
facility. Our heavy oil processing facility will upgrade lower-cost heavy sour
crude oil into higher-value refined products.
The following diagram illustrates the various projects to be completed as
part of the refinery upgrade project.
[REFINERY UPGRADE PROJECT CHART]
1
<PAGE>
The following is a description of the major processing units that are being
constructed or modified as part of the refinery upgrade project:
<TABLE>
<C> <S>
crude unit The crude unit and vacuum tower will be upgraded so that they
will have the capacity to process more and heavier crude oil
by separating it into components that include light gases,
kerosene, gas oil and a residue called vacuum tower bottoms,
all of which require additional processing at the refinery
before becoming commercially saleable.
delayed The new coker will convert vacuum tower bottoms from the
coking unit processing of heavy sour crude oil by the refinery's crude
unit into lighter products such as fuel gas, propane, butane,
gasoline, diesel, lightcycle oil and gas oil, all of which
require additional processing, and petroleum coke, which can
be sold commercially.
vacuum gas oil The new hydrocracker will employ catalyst and hydrogen at
hydrocracker elevated temperatures and pressure to convert gas oil from
our new coking unit and other processing units at the
refinery into lighter products and high quality vacuum gas
oil, which are commercially saleable.
hydrotreaters The hydrotreaters will be upgraded so that they will have
increased capacities to remove nitrogen and sulfur from
kerosene, diesel and other products produced by the
refinery's coking, crude and other units. This process of
hydrotreating turns these products into commercially saleable
finished products.
sulfur complex The new sulfur recovery unit will process the incremental
sulfur that results from the processing of heavy sour crude
oil and will operate in conjunction with an existing sulfur
recovery unit at the refinery.
</TABLE>
Port Arthur Finance Corp., a wholly owned subsidiary of Port Arthur Coker
Company, was incorporated in Delaware in July 1999 for the purpose of issuing
the outstanding notes and borrowing under our bank credit facilities, as agent
on behalf of Port Arthur Coker Company, and transferring the proceeds of the
issuance of notes and borrowing under our bank credit facilities to Port Arthur
Coker Company by means of an intercompany note. Port Arthur Coker Company is
using the proceeds to fund a portion of the costs of the development and
construction of our coker project. Port Arthur Coker Company is owned 1% by its
general partner, Sabine River Holding Corp., and 99% by its limited partner,
Neches River Holding Corp. Both partners were incorporated in Delaware in May
1999. Each of Port Arthur Coker Company, Sabine River and Neches River have
unconditionally guaranteed, on a joint and several basis, all the obligations
of Port Arthur Finance under the outstanding notes and will unconditionally
guarantee, on a joint and several basis, all the obligations of Port Arthur
Finance under the exchange notes.
2
<PAGE>
Planned Ownership Structure
[Flowchart of Ownership Structure]
Sabine River is owned 90% by Clark Refining Holdings Inc. and 10% by
Occidental Petroleum Corporation. After giving effect to the full $135 million
of equity contributions to be made in connection with our coker project, Clark
Refining Holdings will be owned, indirectly through subsidiaries, by Blackstone
Capital Partners III Merchant Banking Fund L.P. and its affiliates with an
approximately 82% interest, and by Occidental with an approximately 17%
interest. We are an affiliate of Clark Refining & Marketing because Clark
Refining Holdings owns 100% of the capital stock of Clark USA, Inc., which in
turn owns 100% of the capital stock of Clark Refining & Marketing.
We and our contractual arrangements have been structured in a manner designed
not to be consolidated with Clark Refining Holdings, Clark USA or Clark
Refining & Marketing in a bankruptcy of any of these entities. As such, you
will have recourse only to us, Sabine River and Neches River and not to any of
our other direct or indirect owners with respect to our obligations on the
notes. We believe that this structure enhances the credit quality of our notes
because our assets, which are mortgaged to secure the notes, should remain
separate from the assets of Clark Refining & Marketing and Clark Refining
Holdings in the event either of those entities were to seek reorganization in
bankruptcy.
Our principal executive offices are located at 1801 S. Gulfway Drive, Office
No. 36, Port Arthur, Texas 77640. Our telephone number is (409) 982-7491.
3
<PAGE>
Our Coker Project
Rationale for Our Coker Project. Blackstone and Clark Refining Holdings have
been pursuing a strategy of positioning Clark Refining Holdings as a leading
independent refiner in the United States by selectively increasing its refining
capacity through acquiring refining assets, improving the productivity of its
existing refineries and divesting non-core assets. This strategy is subject to
costs, industry and financial market risks, operating risks and risk of
increased competition for available assets, among other risks, that may cause
Blackstone and Clark Refining Holdings to be unsuccessful in implementing such
a strategy. The refinery upgrade project is an important element of this
strategy. Purvin & Gertz, the independent engineer, expects that the refinery
upgrade project will transform the Port Arthur refinery into one of the five
most competitive refineries on the U.S. Gulf Coast.
The refinery upgrade project was initiated for the following reasons:
. Port Arthur refinery's suitability for a heavy oil upgrade. Clark
Refining Holdings believes the Port Arthur refinery is well-suited to be
upgraded to process significantly more heavy sour crude oil. Its Gulf
Coast location is close to the major heavy sour crude oil producers and
permits waterborne deliveries of oil. In addition, because the Port
Arthur refinery was originally designed and operated as a much larger
facility with over 400,000 barrels per day of crude oil throughput
capacity, the refinery has the scale, processing capability and much of
the infrastructure including docks, storage tanks, steam and power
generation capability and wastewater treatment facilities to support an
upgraded operation. As a result, Clark Refining Holdings believes the
refinery upgrade project can be undertaken at a lower capital cost than
at many other U.S. Gulf Coast refineries.
. Crude oil cost reduction. Clark Refining Holdings expects to be able to
reduce crude oil costs at the Port Arthur refinery by increasing the
quantities of heavy sour crude oil processed at the Port Arthur refinery
from 20% to 80% of capacity. Heavy sour crude oil typically sells at a
discount when compared with light sweet crude oil because heavy sour
crude oil is more difficult to process.
. Increased cash flow. Purvin & Gertz expects us to generate approximately
$228 million of annual average operating cash flows over the initial 11-
year operating period of our coker project. Clark Refining Holdings
expects Clark Refining & Marketing also to generate incremental cash
flow as a result of the refinery upgrade project. Purvin & Gertz's
projection is subject to assumptions and an alternative conclusion could
be reached using different assumptions. See Annex B to this prospectus
for a discussion of the material assumptions underlying Purvin & Gertz's
projection.
. Margin support. We believe we will benefit from a coker gross margin
support mechanism in our long term crude oil supply agreement with
P.M.I. Comercio Internacional, a subsidiary of Petroleos Mexicanos, also
known as PEMEX, the Mexican national oil company and guarantor of P.M.I.
Comercio Internacional's obligations. This mechanism is designed to
moderate the fluctuations of our coker gross margin, which is the
differential between the price for intermediate refined products from
our coking operations and the cost of coker feedstocks. The term
intermediate refined products is used in the oil industry to refer to
petroleum products that are generally considered to need additional
refining prior to becoming commercially saleable and the term feedstocks
is generally used to refer to the raw materials needed for a refinery
processing unit to produce a particular refined product. This mechanism
is based on a formula that is intended to be an approximation for coker
gross margin and is designed to provide for a minimum average coker
gross margin over the first eight years following completion of the
refinery upgrade project. Purvin & Gertz believes the mechanism will
serve as a suitable method of stabilizing our coker gross margin
fluctuations and that the mechanism equates to an approximate $5.94
heavy/light differential when applied to 1987 to 1998 prices.
General Description. The refinery upgrade project will allow our heavy oil
processing facility to process an average of 200,000 barrels per stream day of
crude oil. At least 150,000 barrels per stream day of heavy sour crude oil will
be purchased from P.M.I. Comercio Internacional under our long term crude oil
supply agreement. All of the output of our heavy oil processing facility will
be purchased by our affiliate, Clark Refining & Marketing, under a long term
product purchase agreement. We expect construction of our coker project and the
entire refinery upgrade project to be mechanically complete around November
2000, and we expect to begin commercial operation around January 2001.
4
<PAGE>
Key Project Contracts. The chart below depicts some of the key contracts
relating to the construction and operation of our coker project and our heavy
oil processing facility which are described in more detail below.
[Flow chart of Key Coker Project Contracts and parties thereto]
Construction of Our Coker Project. We entered into a contract for the
engineering, procurement and construction of our coker project with Foster
Wheeler USA Corporation in July 1999. Foster Wheeler Corporation, the parent of
Foster Wheeler USA, has guaranteed Foster Wheeler USA's payment and performance
obligations under this construction contract.
Under this construction contract, Foster Wheeler USA will continue to
engineer, design, procure equipment for, construct, test and oversee start-up
of our coker project and integrate our coker project with the Port Arthur
refinery. Under the construction contract, we will pay Foster Wheeler USA a
fixed price of approximately $544 million of which $157.1 million was credited
to us for amounts Clark Refining & Marketing had already paid Foster Wheeler
USA for work performed on our coker project prior to August 1999. We purchased
this work in progress from Clark Refining & Marketing when we issued the
outstanding notes. Our construction contract does not cover the work to be
undertaken by Clark Refining & Marketing as part of the refinery upgrade
project. Clark Refining & Marketing has contracted separately with Foster
Wheeler USA to perform the majority of such work.
Under our construction contract, Foster Wheeler USA must demonstrate that our
coker project is mechanically complete and ready for start-up by March 2001. In
addition, Foster Wheeler USA must fulfill all its obligations under the
construction contract and demonstrate achievement of specified guarantees of
capacity and reliability for our coker project by December 2001. If Foster
Wheeler USA demonstrates achievement of mechanical completion of our coker
project prior to our target date of November 2000, it will receive an early
completion bonus.
If our coker project is not mechanically complete and ready for start-up by
January 2001 or Foster Wheeler USA has not demonstrated achievement of 100% of
its guarantee of reliability for our coker project by that date, it must pay us
delay damages. The amount of these delay damages is capped at $70 million. In
5
<PAGE>
addition, if Foster Wheeler USA fails to demonstrate achievement of 100% of its
capacity and reliability guarantees for our coker project, it still may fulfill
its obligations under the construction contract by making specified buydown
payments to us, if Foster Wheeler USA demonstrates achievement of 95% of their
reliability guarantee for our coker project and specified minimum capacities
for each of our new units. These buydown payments are capped at $75 million.
Foster Wheeler USA may be liable for damages under the construction contract up
to 100% of the contract price. This liability cap, however, does not apply to
damages arising out of Foster Wheeler USA's indemnification obligations.
Work on our coker project is well advanced. As of January 2000, 100% of major
equipment procurement, 89% of total materials procurement and 98% of detailed
design and engineering were complete and construction was 31% complete.
Construction activities to date have included site preparation, foundations and
footings installation, major equipment installation and pipe rack construction.
In June 1999, the six coke drums for our new delayed coking unit arrived at the
Port Arthur refinery and by October 1999 were all installed in their support
structures. In January 2000, approximately 175 people were working on design
and engineering and approximately 965 people are working on construction of our
coker project.
As part of the refinery upgrade project, Air Products will construct and own
a new hydrogen supply plant at the Port Arthur refinery on land leased from
Clark Refining & Marketing. This new hydrogen supply plant is designed to
supply hydrogen to us, as well as hydrogen, steam and electricity to Clark
Refining & Marketing, for use at the Port Arthur refinery. Air Products is
obligated to ensure that the hydrogen supply plant is ready to operate no later
than December 2000, the date when we expect our heavy oil processing facility
to first need hydrogen.
Our Operations. Clark Refining & Marketing has agreed to provide us with
services necessary to complete our coker project and to operate the heavy oil
processing facility. Under our services and supply agreement, the services to
be performed by Clark Refining & Marketing include, among others, the
following:
. oversight of the construction of our new units and other equipment and
performance of our obligations under our construction contract with
Foster Wheeler USA, other than our payment obligations;
. operation and maintenance of the ancillary units and equipment that we
are leasing from Clark Refining & Marketing;
. management of the operation and maintenance of our new processing units
and other equipment at the Port Arthur refinery;
. management of our crude oil purchases and transportation of our crude oil
to the Port Arthur refinery; and
. supply of other required feedstocks, materials and utilities.
In addition, under our services and supply agreement Clark Refining &
Marketing has a right of first refusal to require us to process crude oil for
them in an amount equal to approximately 20% of the processing capacity of our
heavy oil processing facility. We and Clark Refining & Marketing will receive
fees from each other for providing services. The actual fee and how it will be
recorded will vary based on the type of service provided. Some fees will be
based on a sharing of costs while others will include profit margin, but such
fees were intended to approximate fair market value in the aggregate. Fees will
be capitalized, expensed or charged to cost of goods sold, as appropriate.
Our Supply of Crude Oil. We expect to receive the heavy sour crude oil to be
processed by our heavy oil processing facility from P.M.I. Comercio
Internacional under our long term crude oil supply agreement. Petroleos
Mexicanos, the parent of P.M.I. Comercio Internacional, which is often referred
to in the oil industry as PEMEX, has guaranteed P.M.I. Comercio Internacional's
obligations under our long term crude oil supply
6
<PAGE>
agreement. The type of Mexican heavy sour crude oil available to us under our
long-term oil supply agreement is called Maya.
Our long term crude oil supply agreement includes a mechanism designed to
minimize the effect of adverse refining cycles and to moderate the fluctuations
of our coker gross margin. This mechanism contains a formula that is intended
to be an approximation for coker gross margin and is designed to provide for a
minimum average coker gross margin over the first eight years following
completion of the refinery upgrade project, if it is completed by July 2001.
This eight year period will be shortened by any period of delay in completion
of the refinery upgrade project beyond July 2001 unless the delay is caused by
events beyond our reasonable control.
Sale of Our Refined Products. We have entered into a product purchase
agreement with Clark Refining & Marketing for the sale of all refined and
intermediate products produced by our heavy oil processing facility. Under our
product purchase agreement, Clark Refining & Marketing is obligated to accept
and pay for all our products and has a limited right to request that we produce
a specified mix of products. The prices that we are paid for our products by
Clark Refining & Marketing are determined by formulas that are based on
published market benchmark prices, as they may vary from time to time. We
believe that the pricing mechanism reflects an arm's-length fair market price
between us and Clark Refining & Marketing. These prices are determined at the
time of delivery to Clark Refining & Marketing, so we bear the market risk of
any change in the relative prices of Maya and our other feedstocks and the
prices of our products during the time that we are refining the crude oil.
Independent Engineer's Report. Purvin & Gertz, Inc., in its role as
independent engineer, prepared a report dated August 10, 1999, which discusses
certain technical, environmental and economic aspects of the Refinery Upgrade
Project. This report is set forth in its entirety as Annex B to this prospectus
and a summary of the report is included under "Independent Engineer's Report
Summary." This report includes, among other things, Purvin & Gertz's
projections of operating results, including projected revenues, expenses and
debt service coverage ratios during the period the notes are scheduled to
remain outstanding, a design basis review of our coker project and the Port
Arthur refinery and a review of our principal project contracts. In addition,
the report contains a discussion of whether, and the extent to which, we would
be able to operate on a "stand-alone" basis without our services and supply
agreement and product purchase agreement with Clark Refining & Marketing.
Crude Oil and Refined Product Market Report. In addition, Purvin & Gertz, in
its role as our independent marketing consultant, prepared a crude oil and
refined product market forecast report dated July 13, 1999. This report
includes price forecasts for crude oil and refined products, and discusses the
effect on our coker project of fluctuations in heavy sour crude oil
availability, the costs of heavy sour crude oil and the prices at which refined
products may be sold. This report is set forth in its entirety as Annex C to
this prospectus and a summary of Purvin & Gertz's report is included under
"Crude Oil and Refined Product Market Report Summary."
7
<PAGE>
Our Financing Plan
We estimate that we will need approximately $715 million to pay all of the
costs of developing, constructing, financing and commissioning our coker
project. Of this amount, approximately $255 million has been raised from the
sale of the outstanding notes which bear interest at a fixed rate of 12.5% per
year, approximately $325 million will come from our secured construction and
term loan facility provided by commercial banks and institutional lenders and
approximately $135 million will come from equity contributions by Blackstone
and Occidental. The construction and term loan facility is split into a Tranche
A of $225 million, at a variable rate equal to LIBOR plus 4.75%, with a term of
7.5 years and a Tranche B of $100 million, at an interest rate of LIBOR plus
5.25%, with a term of 8 years. Our contractual arrangements with Blackstone and
Occidental provide that the aggregate $135 million equity commitment will be
funded pro rata with the funding of our notes and bank term debt, so that at
the time of each advance of debt and equity to pay our construction costs the
amount funded will be approximately 65% debt and 35% equity. As of February 29,
2000, approximately $61 million of the $135 million of equity had been funded.
We expect the remaining $74 million of equity to be funded by March 2001.
The following table set forth our expected sources and uses of funds.
<TABLE>
<CAPTION>
Amounts
------------------------
(in millions of dollars)
<S> <C>
Sources
Construction and term loans......................... $325
The outstanding notes............................... 255
Equity contributions................................ 135
----
Total Sources......................................... $715
====
Uses
Construction contract............................... $544
Coker project contingency........................... 28
Interest during construction, net of interest
income............................................. 89
Start-up, development, asset acquisition and other
construction costs................................. 22
Financing costs, legal and other transaction costs.. 32
----
Total Uses............................................ $715
====
</TABLE>
Interest expense during construction, net of interest income was calculated
in the Purvin & Gertz base case model using the expected construction timeline,
related funding requirements and interest rates of 12.50% on the outstanding
notes and 10.75% construction and term loan facility.
8
<PAGE>
Summary of Terms of the Exchange Offer
On August 19, 1999, Port Arthur Finance completed the private offering of the
outstanding notes. References to "notes" in this prospectus are references to
both outstanding notes and the exchange notes.
Port Arthur Finance, Port Arthur Coker Company, Sabine River Holding Corp.
and Neches River Holding Corp. entered into a registration rights agreement
with the initial purchasers in the private offering in which we agreed to
deliver to you this prospectus and Port Arthur Finance agreed to complete the
exchange offer within 270 days after the date of original issuance of the
outstanding notes. In the exchange offer, you are entitled to exchange your
outstanding notes for exchange notes which are identical in all material
respects to the outstanding notes except that:
. the exchange notes have been registered under the Securities Act,
. the exchange notes are not entitled to all registration rights under the
registration rights agreement, and
. some of the contingent interest rate provisions of the registration
rights agreement are no longer applicable.
The Exchange Offer.......... Port Arthur Finance is offering to exchange up to
$255 million aggregate principal amount of
exchange notes for up to $255 million aggregate
principal amount of outstanding notes.
Outstanding notes may be exchanged only in
integral multiples of $1,000.
Resale...................... Based on an interpretation by the staff of the
Securities and Exchange Commission, the
Commission, set forth in no-action letters issued
to third parties, we believe that the exchange
notes issued in the exchange offer in exchange
for outstanding notes may be offered for resale,
resold and otherwise transferred by you without
compliance with the registration and prospectus
delivery provisions of the Securities Act,
provided that:
. you are acquiring the exchange notes in the
ordinary course of your business;
. you have not engaged in, do not intend to
engage in, and have no arrangement or
understanding with any person to participate
in the distribution of exchange notes; and
. you are not an "affiliate" of Port Arthur
Finance within the meaning of Rule 405 of the
Securities Act.
Each participating broker-dealer that receives
exchange notes for its own account during the
exchange offer in exchange for shares of
outstanding notes that were acquired as a result
of market-making or other trading activity must
acknowledge that it will deliver a prospectus in
connection with any resale of the exchange notes.
Prospectus delivery requirements are discussed in
greater detail in the section captioned "Plan of
Distribution."
9
<PAGE>
Any holder of outstanding notes who
. is an affiliate of Port Arthur Finance
. does not acquire exchange notes in the
ordinary course of its business, or
. tenders in the exchange offer with the
intention to participate, or for the purpose
of participating, in a distribution of
exchange notes,
cannot rely on the position of the staff of the
Commission enunciated in Exxon Capital Holdings
Corporation, Morgan Stanley & Co. Incorporated or
similar no-action letters and, in the absence of
an exemption, must comply with the registration
and prospectus delivery requirements of the
Securities Act in connection with the resale of
the exchange notes.
Expiration Date; Withdrawal
of Tenders..................
The expiration date of the exchange offer will be
at 5:00 p.m., New York city time, on , 2000,
or such later date and time to which Port Arthur
Finance extends it. A tender of outstanding notes
in connection with the exchange offer may be
withdrawn at any time prior to the expiration
date. Any outstanding notes not accepted for
exchange for any reason will be returned without
expense to the tendering holder promptly after
the expiration or termination of the exchange
offer.
Conditions to the Exchange
Offer.......................
The exchange offer is subject to customary
conditions, which Port Arthur Finance may waive.
Please read the section captioned "The Exchange
Offer--Conditions to the Exchange Offer" of this
prospectus for more information regarding the
conditions to the exchange offer.
Procedures for Tendering
Outstanding Notes...........
If you wish to accept the exchange offer, you
must complete, sign and date the accompanying
letter of transmittal, or a facsimile of the
letter of transmittal, according to the
instructions contained in this prospectus and the
letter of transmittal. You must also mail or
otherwise deliver the letter of transmittal, or a
facsimile of the letter of transmittal, together
with the outstanding notes and any other required
documents to the exchange agent at the address
set forth on the cover page of the letter of
transmittal. If you hold outstanding notes
through The Depository Trust Company, DTC, and
wish to participate in the exchange offer, you
must comply with the Automated Tender Offer
Program procedures of DTC, by which you will
agree to be bound by the letter of transmittal.
By signing, or agreeing to be bound by, the
letter of transmittal, you will represent to us
that, among other things:
. any exchange notes that you receive will be
acquired in the ordinary course of your
business;
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. you have no arrangement or understanding with
any person or entity to participate in the
distribution of the exchange notes;
. if you are a broker-dealer that will receive
exchange notes for your own account in
exchange for outstanding notes that were
acquired as a result of market-making
activities, that you will deliver a
prospectus, as required by law, in connection
with any resale of the exchange notes; and
. you are not an "affiliate," as defined in Rule
405 of the Securities Act, of Port Arthur
Finance or, if you are an affiliate, you will
comply with any applicable registration and
prospectus delivery requirements of the
Securities Act.
Special Procedures for
Beneficial Owners...........
If you are a beneficial owner of outstanding
notes which are not registered in your name, and
you wish to tender outstanding notes in the
exchange offer, you should contact the registered
holder promptly and instruct the registered
holder to tender on your behalf. If you wish to
tender on your own behalf, you must, prior to
completing and executing the letter of
transmittal and delivering your outstanding
notes, either make appropriate arrangements to
register ownership of the outstanding notes in
your name or obtain a properly completed bond
power from the registered holder.
Guaranteed Delivery
Procedures..................
If you wish to tender your outstanding notes and
your outstanding notes are not immediately
available or you cannot deliver your outstanding
notes, the letter of transmittal or any other
documents required by the letter of transmittal
or comply with the applicable procedures under
DTC's Automated Tender Offer Program prior to the
expiration date, you must tender your outstanding
notes according to the guaranteed delivery
procedures set forth in this prospectus under
"The Exchange Offer--Guaranteed Delivery
Procedures."
Consequences of Failure to
Exchange....................
All untendered outstanding notes will continue to
be subject to the restrictions on transfer
provided for in the outstanding notes and in the
indenture. In general, the outstanding notes may
not be offered or sold, unless registered under
the Securities Act, except in compliance with an
exemption from, or in a transaction not subject
to, the Securities Act and applicable state
securities laws. Other than in connection with
the exchange offer, Port Arthur Finance does not
currently anticipate that it will register the
outstanding notes under the Securities Act.
U.S. Federal Income Tax
Considerations..............
The exchange of outstanding notes for exchange
notes in the exchange offer will not be a taxable
event for U.S. federal income tax purposes.
Please read the section of this prospectus
captioned
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<PAGE>
"U.S. Federal Income Tax Consequences of the
Exchange Offer" for more information on tax
consequences of the exchange offer.
Use of Proceeds............. We will not receive any cash proceeds from the
issuance of exchange notes in the exchange offer.
Exchange Agent.............. HSBC Bank USA is the exchange agent for the
exchange offer. The address and telephone number
of the exchange agent are set forth in the
section captioned "Exchange Offer--Exchange
Agent" of this prospectus.
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<PAGE>
Summary of Terms of the Exchange Notes
Issuer.................... Port Arthur Finance Corp., as agent acting on
behalf of Port Arthur Coker Company L.P.
Guarantors................ Each of Port Arthur Coker Company L.P., Sabine
River Holding Corp. and Neches River Holding Corp.
have unconditionally guaranteed, on a joint and
several basis, all the obligations of Port Arthur
Finance Corp. under the outstanding notes and will
unconditionally guarantee, on a joint and several
basis, all the obligations of Port Arthur Finance
Corp. under the exchange notes.
Securities Offered........ $255 million in principal amount of 12.50% senior
secured notes due 2009.
Maturity Date............. January 15, 2009.
Interest Payment Dates.... January 15 and July 15 of each year, commencing on
January 15, 2000.
Scheduled Principal We are required to pay principal of the notes on
Payments................. each January 15 and July 15, commencing July 15,
2002, as follows:
<TABLE>
<CAPTION>
Percentage of Principal
Payment Date Amount Payable
------------ -----------------------
<S> <C>
July 15, 2002......................... 1.70%
January 15, 2003...................... 1.70%
July 15, 2003......................... 4.10%
January 15, 2004...................... 4.10%
July 15, 2004......................... 6.00%
January 15, 2005...................... 6.00%
July 15, 2005......................... 9.10%
January 15, 2006...................... 9.10%
July 15, 2006......................... 9.10%
January 15, 2007...................... 9.10%
July 15, 2007......................... 7.90%
January 15, 2008...................... 7.90%
July 15, 2008......................... 12.10%
January 15, 2009...................... 12.10%
</TABLE>
Initial Average Life of
the Notes................
Approximately 7.0 years.
Form and Denomination..... We will issue the exchange notes in global form in
minimum denominations of $100,000 or any integral
multiple of $1,000 in excess of $100,000.
Ranking................... The notes:
. are senior secured indebtedness;
. are equivalent in right of payment to all our
existing and future senior indebtedness; and
. rank senior to any of our subordinated
indebtedness.
Limited Recourse The obligations to pay principal of, and interest
Obligations.............. and premium, if any, on the notes are solely the
obligations of us, Sabine River and Neches River.
You will not have any recourse against our other
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<PAGE>
owners and affiliates, including Clark Refining &
Marketing, Clark USA, Clark Refining Holdings,
Blackstone and Occidental, for any failure by any
of us, Sabine River or Neches River to satisfy
obligations under the notes.
Collateral................ Payment of the outstanding notes and our other
senior debt is, and the exchange notes when issued
will be, secured by security interests in
substantially all of our assets, including those
described under the heading "Description of Our
Principal Financing Documents--Common Security
Agreement--Scope and Nature of the Security
Interests."
Collateral Sharing........ The collateral is shared equally and ratably with
the other senior lenders, any replacement senior
lenders and the oil payment insurers in the manner
described in "Description of Our Principal
Financing Documents--Common Security Agreement" and
"--Intercreditor Agreement."
Redemption at our Option.. We may choose to redeem some or all of the notes at
any time, without the consent of noteholders, at a
redemption price equal to:
. 100% of the unpaid principal amount of notes
being redeemed, plus
. accrued and unpaid interest, if any, on the notes
being redeemed, up to but excluding the date of
redemption, 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 of principal of the notes plus
75 basis points.
Mandatory Redemption...... If we receive specified mandatory prepayment
proceeds, including specified insurance and other
recovery proceeds from casualty events,
condemnation compensation and late payments to the
extent not needed for payments of interest, and
buydown payments from Foster Wheeler USA, we will
be required to redeem all our outstanding senior
debt, including the notes, on a ratable basis. The
redemption price for the notes will be equal to:
. 100% of the unpaid principal amount of notes
being redeemed, plus
. accrued but unpaid interest, if any, on the notes
being redeemed, up to but excluding the date of
redemption.
Common Security We, Sabine River and Neches River have entered into
Agreement................. a common security agreement with the collateral
trustee, the bank lenders administrative agent, the
oil payment insurers administrative agent, the
indenture trustee and the depositary bank. The
common security agreement sets forth common
representations, warranties, covenants, a common
security package for the benefit of the secured
parties, events of default and remedies relating to
our coker project and common conditions to
disbursement of senior loans. The common security
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<PAGE>
agreement also contains restrictions on our ability
to make distributions to our owners and to incur
additional or replacement senior debt. The terms of
the common security agreement are discussed in
"Description of Our Principal Financing Documents--
Common Security Agreement."
Ownership and Control..... Blackstone does not have the right to dispose of
its equity interest in Clark Refining Holdings,
except in limited circumstances described under
"Description of Our Principal Financing Documents--
Transfer Restrictions Agreement."
In addition, Clark Refining Holdings may not
dispose of its indirect interest in the Port Arthur
refinery, Clark Refining & Marketing or Port Arthur
Coker Company, except in limited circumstances
following final completion of our coker project as
described under "Description of Our Principal
Financing Documents--Transfer Restrictions
Agreement."
15
<PAGE>
RISK FACTORS
You should carefully consider the following information, together with the
other information in this prospectus, before tendering your outstanding notes.
Construction Risks
Construction of our coker project and/or the refinery upgrade project could be
delayed for reasons beyond our control or beyond our contractors' control.
Under a fixed price turnkey construction contract, Foster Wheeler USA has
guaranteed final completion of our coker project by December 2001, and under a
separate performance guarantee, Foster Wheeler Corporation has guaranteed
Foster Wheeler USA's performance under this construction contract. Under a
separate contract with Clark Refining & Marketing, Foster Wheeler USA has
agreed to complete Clark Refining & Marketing's portion of the refinery upgrade
project by that date as well. In addition, Air Products has agreed to complete
construction of a hydrogen supply plant at the Port Arthur refinery by December
2000, which is necessary for our heavy oil processing facility. Other than the
equity commitments of Blackstone and Occidental in the aggregate amount of
approximately $135 million, neither Blackstone nor Occidental is obligated to
cause completion or otherwise provide any completion support. The construction
and timely completion of our coker project and of the entire refinery upgrade
project could be delayed for reasons beyond our control and the control of our
contractors, including the following:
. shortages of equipment, materials and labor;
. work stoppages and other labor disputes;
. litigation;
. unanticipated increases in costs;
. adverse weather conditions and natural disasters; and
. accidents.
If any of these events or other unanticipated events occur, the construction
of our coker project, the refinery upgrade project and/or the hydrogen supply
plant may be delayed, our coker project may cost us more to complete than we
have currently budgeted, or our coker project may not perform as well as we
expect it to, which could cause us to be unable to make payments on the notes
and our other debt when due.
We cannot guarantee that our coker project has been properly designed or that
our coker project will be successfully integrated with the Port Arthur
refinery.
The successful operation of our coker project is subject to engineering and
design uncertainties. We cannot be sure that our coker project will operate as
designed or that it will be integrated effectively with the Port Arthur
refinery. A delay in the successful integration of our coker project with the
Port Arthur refinery would materially affect our ability to generate revenues
and make payments on the notes and our other debt when due.
The liquidated damages that we may receive from Foster Wheeler USA and Air
Products for construction delays or failures to satisfy performance
requirements may not be sufficient to compensate us for our resulting losses.
Foster Wheeler USA is obligated to pay us liquidated damages in the event of
delays in construction or the failure of our coker project to satisfy standards
relating to capacity, efficiency and reliability. Similarly, Air
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<PAGE>
Products is obligated to pay us limited liquidated damages in the event the
hydrogen supply plant is not completed on time. These liquidated damages are
subject to caps and may otherwise not be sufficient to cover the losses that
we could incur as a result of construction delays or failures to satisfy
performance requirements. As a result, a delay in construction or a failure of
our coker project to satisfy performance requirements--notwithstanding that we
may be entitled to receive liquidated damages under our construction contract
or our hydrogen supply agreement--could cause us to be unable to make payments
on the notes and our other debt when due.
If construction of our coker project is delayed, P.M.I. Comercio Internacional
may be able to terminate our long term crude oil supply agreement, which would
cause us to lose the benefit of our coker gross margin support mechanism.
Under our long term crude oil supply agreement with P.M.I. Comercio
Internacional, we must complete the refinery upgrade project by January 2001
or make specified payments to P.M.I. Comercio Internacional to extend this
scheduled completion date. If we must extend this scheduled completion date
beyond July 2001, the coker gross margin support mechanism will terminate in
July 2009, unless extended by an event beyond our reasonable control that
delays completion, like a fire, an earthquake or an act of a governmental
authority. Therefore, if the completion of the refinery upgrade project has
not occurred for any reason other than an event beyond our reasonable control
by July 2001, we will have the benefit of the coker gross margin support
mechanism in our long term oil supply agreement for a period shorter than
eight years. If we do not make payments to extend this scheduled completion
date and it is not extended by an event beyond our reasonable control, P.M.I.
Comercio Internacional will have the right to terminate our long term crude
oil supply agreement and we would be liable to P.M.I. Comercio Internacional
for damages. If this were to occur, we would lose the benefit of the coker
gross margin support mechanism contained in our long term crude oil supply
agreement, which could impair our ability to make payments on the notes and
our other debt when due.
Market Risks
Our cash flows are subject to fluctuations in the market prices of crude oil,
other feedstocks and refined products, which are beyond our control and which
may be volatile.
Our net operating cash flow will be a function of the cost of heavy sour
crude oil which we purchase and the price at which our refined products may be
sold. The price we must pay at any time for crude oil and the prices paid to
us at any time for our refined products by Clark Refining & Marketing under
our product purchase agreement will be based upon prevailing market prices of
similar commodities. The markets and prices of these commodities are subject
to considerable fluctuation and depend upon many factors beyond our control,
such as the following:
. the aggregate demand for crude oil and refined products, which are
influenced by factors such as the state of the economy and weather
patterns;
. the prices and availability of imports of refined products and
feedstocks;
. refining industry utilization rates within the industry;
. the prices and availability of alternative products;
. the impact of energy conservation efforts;
. international political and economic events;
. the level of taxation; and
. aggregate refinery capacity in the oil refining industry to convert heavy
sour crude oil into refined products.
Any of these factors could affect the price differential between the price
of heavy sour crude oil and refined products. We cannot guarantee that the
differential will not decrease below the amount needed for us to generate net
cash flow sufficient to make payments on the notes and other debt when due.
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<PAGE>
The coker gross margin support mechanism in our long term crude oil supply
agreement with P.M.I. Comercio Internacional may not adequately protect us from
fluctuations in the relative prices of heavy sour crude oil and refined
products.
Our long term crude oil supply agreement with P.M.I. Comercio Internacional
includes a coker gross margin support mechanism based on a formula that is
intended to be an approximation for coker gross margin and is designed to
provide for a minimum average coker gross margin over the first eight years
following completion of the refinery upgrade project, assuming we achieve
completion by July 2001. However, this mechanism covers our coker gross
margins, not margins of all products produced by our heavy oil processing
facility. In addition, the formula incorporates variables based on benchmark
products that are proxies for actual feedstocks and outputs rather than the
feedstocks and outputs themselves. Finally, the relationships among the
variables in the formula could change over time, reflecting a change in the
market for the products, and the agreement provides for adjustments if these
relationships change. We cannot assure you that the coker gross margin support
mechanism will adequately protect us against fluctuations in the relative
prices of heavy sour crude oil and refined products.
The projections and assumptions about our future performance may prove to be
inaccurate.
We were formed for the purpose of developing, constructing and operating our
heavy oil processing facility and have no operating history. Moreover, because
our coker project is not yet complete, we have no actual operating results. As
a result, the financing of our coker project is based upon assumptions and
financial projections regarding our revenues and operating, maintenance and
capital costs, including that Clark Refining & Marketing will exercise its
right to utilize our excess processing capacity.
Purvin & Gertz, in its role as an independent consultant, has reviewed the
refinery upgrade project and prepared reports on the technical, environmental
and economic aspects of the refinery upgrade project. Purvin & Gertz's
"Independent Engineer's Report," dated August 10, 1999, and its "Crude Oil and
Refined Product Market Report," dated July 13, 1999 are provided to you as
Annexes B and C of this prospectus. In preparing the reports, Purvin & Gertz
utilized actual oil prices through June 1999. The reports set forth Purvin &
Gertz's projections for our operations and include discussions of the many
assumptions utilized by Purvin & Gertz in preparing their projections. Among
the many assumptions used by Purvin & Gertz in developing these projections are
construction costs, operating expenses, market prices of feedstocks and refined
products, repair and maintenance costs, efficiency of operations, the ability
of Clark Refining & Marketing to perform its contractual obligations, the
market for our refined products if Clark Refining & Marketing defaults in its
product purchase obligations, tax payments, inflation and capital costs.
These assumptions contain significant uncertainties. Although we and Purvin &
Gertz believe that the assumptions made are reasonable, neither we nor Purvin &
Gertz nor any other person assumes any responsibility for their accuracy.
Therefore, we can make no representation about the likely existence of any
particular future set of facts or circumstances. Purvin & Gertz's projections
are not necessarily an indication of our future performance. In fact, our
actual results will differ, perhaps materially, from those projected. If our
actual results are less favorable than those projected, or if the assumptions
Purvin & Gertz used in preparing their financial projections prove to be
incorrect, we may be unable to make payments on the notes and our other debt
when due.
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<PAGE>
Operating Risks
We may not be able to operate on a "stand-alone" basis.
Our heavy oil processing facility was not designed to operate on a "stand-
alone" basis.,In the event of bankruptcy or other material interruption in the
operations of Clark Refining & Marketing we may not be able to operate
economically because our dependence on Clark Refining & Marketing would limit
our ability to obtain feedstock, deliver products and obtain other services and
supplies from parties unaffiliated with Clark Refining & Marketing. Thus, we
cannot assure you that we would in fact be able to operate on a stand-alone
basis without Clark Refining & Marketing.
Our operations involve many risks common to other similar industrial
facilities, including technology risk, operating risk, availability risk and
the risk of events beyond our control.
Our operations will involve many risks, such as the following:
. breakdown or failure of necessary equipment or processes;
. inability to obtain required materials such as Maya and hydrogen;
. inability to dispose of hazardous waste products produced by our
operations;
. the discovery of technological design defects; and
. the occurrence of events beyond our control, such as fires, explosions,
earthquakes, floods and changes in law and eminent domain proceedings.
The occurrence of the kinds of events listed above could significantly
decrease our revenues and/or significantly increase our costs and therefore
impair our ability to make payments on the notes and our other debt when due.
Our insurance coverage may not be adequate.
We will maintain customary insurance for our operations, including builder's
risk, commercial general liability, business interruption insurance and
contingent business interruption insurance. However, not all operating risks
are insurable and the insurance proceeds applicable to covered risks may not be
adequate to cover lost revenues, increased expenses or other costs related to
these occurrences. In addition, the insurance that we currently have may not be
available in the future at commercially reasonable rates.
Our operations are subject to substantial permitting and regulatory
requirements, and our failure to comply with these requirements could subject
us to material liability.
Like many operations in the oil and gas industry, our coker project is
required to obtain and maintain a number of permits and to comply with
constantly changing provisions in numerous statutes and regulations relating
to, among other things, construction, improvements, business operations, the
safety and health of employees and the public, employment, hiring and anti-
discrimination. These requirements may impose significant additional costs on
us, and may even result in civil or criminal liability. There can be no
assurance that we and our contractors and suppliers will at all times be in
compliance with all applicable statutes and regulations or have all necessary
permits in place, nor can we assure you that we will be able to operate our
coker project in accordance with all our permits and approvals. Furthermore,
because of the integration of our coker project with the operations of the Port
Arthur refinery, failure by Clark Refining & Marketing to obtain and maintain
all necessary permits or to be in compliance at all times with applicable
regulations also could affect our financial condition or results of operations.
Any of these circumstances could impair our ability to make payments on the
notes and our other debt when due.
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<PAGE>
Risks Associated with our Reliance on Clark Refining & Marketing
We are relying on Clark Refining & Marketing as our sole source of revenue for
the sale of our refined products.
We have entered into a product purchase agreement with Clark Refining &
Marketing that obligates Clark Refining & Marketing to purchase all of our
refined products tendered for delivery. We have not entered into any
arrangements with any other party for the sale of our refined products. Thus,
our source of revenue for the sale of our refined products will be payments by
Clark Refining & Marketing under our product purchase agreement and, if Clark
Refining & Marketing exercises its right of first refusal, processing fees from
Clark Refining & Marketing under our services and supply agreement. You should
note that under our product purchase agreement, Clark Refining & Marketing may
suspend its obligations to purchase our output if specified events beyond the
control of Clark Refining & Marketing occur, such as interruptions in the
delivery of crude oil to the Port Arthur refinery, adverse weather conditions,
labor disputes or changes in law. Furthermore, under specified circumstances,
Clark Refining & Marketing may terminate our product purchase agreement if we
fail to deliver the refined products substantially in accordance with the terms
of the agreement. If any of these events occur, or if Clark Refining &
Marketing should default on its purchase obligations, we cannot assure you that
a third-party market will be available for our refined products or that our
operating margins will be sufficient to enable us to make payments on the notes
and our other debt when due.
We are relying on Clark Refining & Marketing to manage our operations.
We have entered into a services and supply agreement with Clark Refining &
Marketing that obligates Clark Refining & Marketing to manage our heavy oil
processing facility. In the event Clark Refining & Marketing fails to perform
its obligations under the services and supply agreement, we would need to hire
additional employees and/or enter into other arrangements to provide for
services and supplies previously provided by Clark Refining & Marketing. We
cannot give you any assurance that such employees and services will be readily
available and will have the skills and capacity necessary to operate our heavy
oil processing facility, or, if they are available, that they will be available
on terms as favorable as those of our services and supply agreement with Clark
Refining & Marketing. Thus, if Clark Refining & Marketing breaches its
obligations to us, or terminates our services and supply agreement, our
operating expenses could increase materially and we could be unable to make
payments on the notes and our other debt when due.
We may have conflicts of interest under our various arrangements with Clark
Refining & Marketing.
We have numerous contracts and relationships with Clark Refining & Marketing,
including our services and supply agreement, our product purchase agreement and
various leases. In negotiating these contracts, we and Clark Refining &
Marketing intended to provide terms that are substantially similar to those
that might have been obtained from unaffiliated third parties. However, we
cannot assure you that any of these arrangements actually meet that standard.
Furthermore, in carrying out its obligations under our services and supply,
product purchase and other contracts, including its obligations to resolve
disputes under those contracts, Clark Refining & Marketing may face conflicts
of interest in making decisions that affect us. Although Clark Refining &
Marketing has agreed to carry out its obligations to us in a manner that is
nondiscriminatory to us, as a practical matter our ability to monitor
compliance by Clark Refining & Marketing is limited. As a result, we cannot
guarantee that Clark Refining & Marketing will carry out its obligations to us
in a manner that is nondiscriminatory to us.
The bankruptcy of Clark Refining & Marketing could cause our assets and
liabilities to be consolidated with those of Clark Refining & Marketing and
could prevent us from making payment on the notes.
We have taken steps to maintain the legal existence of Port Arthur Coker
Company, Port Arthur Finance, Sabine River and Neches River independent from
that of Clark Refining & Marketing, Clark USA and Clark Refining Holdings.
However, in a bankruptcy filing by Clark Refining & Marketing, Clark Refining
Holdings or Clark USA, a court could, under the doctrine of substantive
consolidation, disregard our separate existence and order the consolidation of
our assets and liabilities with those of Clark Refining & Marketing, Clark
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Refining Holdings and Clark USA. If a court were to reach this conclusion, we
could be prevented from paying amounts due on the notes and our other debt when
due and the court could order that the collateral securing our senior debt,
including the notes, be shared with debt holders of Clark Refining & Marketing.
Furthermore, a court could set aside payments previously made by us to
noteholders by finding that the distributions were preferential payments made
in violation of bankruptcy laws. Finally, even if a court were to decide
ultimately that our assets should not be consolidated with those of Clark
Refining & Marketing, Clark Refining Holdings and Clark USA, during the
pendency of the bankruptcy proceeding, we might be prevented from making
payments on the notes and our other debt when due.
Risks Associated with our Relationship with P.M.I. Comercio Internacional
We are highly dependent upon P.M.I. Comercio Internacional and PEMEX for our
supply of heavy sour crude oil.
Our long term crude oil supply agreement with P.M.I. Comercio Internacional
obligates it to supply all heavy sour crude oil needed by us. P.M.I. Comercio
Internacional indirectly obtains its supply of heavy sour crude oil under a
separate supply arrangement with Pemex Exploracion y Produccion. Therefore,
P.M.I. Comercio Internacional's ability to deliver heavy sour crude oil is
influenced by the adequacy of Pemex Exploracion's crude oil reserves, the
estimates of which are not precise and are subject to revision at any time. We
have not entered into any other arrangements to supply us with heavy sour crude
oil. In the event P.M.I. Comercio Internacional were to terminate our long term
crude oil supply agreement or default on its supply obligations, we would lose
the benefits of our coker gross margin support mechanism and would need to
obtain heavy sour crude oil from another supplier. If either of these events
were to occur, we cannot guarantee you that an alternative supply of crude oil
would be available. Furthermore, even if we were able to obtain an alternative
supply of heavy sour crude oil, that supply may not be on terms as favorable as
those negotiated with P.M.I. Comercio Internacional. In addition, the
processing of oil supplied by a third party may require changes to our heavy
oil processing facility, which could require significant unbudgeted capital
expenditures. As a result, our ability to make payments on the notes and our
other debt when due may be impaired.
Our supply of heavy sour crude oil from P.M.I. Comercio Internacional could be
interrupted by events beyond its control.
P.M.I. Comercio Internacional's obligation to deliver heavy sour crude oil
under our long term crude oil supply agreement may be delayed or excused by the
occurrence of conditions and events beyond the reasonable control of P.M.I.
Comercio Internacional, such as the following:
. weather-related conditions;
. production or operational difficulties and blockades;
. embargoes or interruptions, declines or shortages of P.M.I. Comercio
Internacional's supply of Maya available for export from Mexico,
including shortages due to increased domestic demand and other national
or international political events; and
. laws, changes in laws, decrees, directives or actions, other than those
that are not common to other similar long term crude oil supply
agreements, of the government of Mexico.
The occurrence of any of these or similar events beyond its reasonable control
could excuse P.M.I. Comercio Internacional from delivering heavy sour crude
oil, and could therefore require us to obtain heavy sour crude oil from another
source. If this were to occur, our ability to make payments on the notes and
our other debt when due could be impaired.
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<PAGE>
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 other long term crude oil supply agreements and the amount by
which it reduces the quantity of Maya to be sold to us shall first be applied
to reduce quantities of Maya 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 the Organization of Petroleum Exporting
Countries, but in 1998 it agreed with the governments of Saudi Arabia and
Venezuela to reduce Mexico's exports of crude oil by 200,000 barrels per day.
In March 1999, Mexico further agreed to cut exports of crude oil by an
additional 125,000 barrels per day. 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. We cannot guarantee that PEMEX will not reduce our
supply of crude oil by similarly invoking the excuse provisions for events
beyond P.M.I. Comercio Internacional's reasonable control agreement in the
future.
We may not be able to enforce civil liabilities against P.M.I. Comercio
Internacional.
P.M.I. Comercio Internacional is organized under the laws of the United
Mexican States. PEMEX, P.M.I. Comercio Internacional's parent and guarantor of
P.M.I. Comercio Internacional's obligations under our long-term crude oil
supply agreement, is a public entity of the United Mexican States. All or a
substantial portion of the assets of PEMEX and P.M.I. Comercio Internacional
and their respective directors and officers are located outside the United
States. As a result, investors may not be able to serve process within the
United States upon P.M.I. Comercio Internacional, PEMEX or their respective
directors or officers, or to enforce against them, in United States courts, any
judgment based solely upon civil liability provisions of the laws of
jurisdictions other than the United Mexican States.
Furthermore, in some cases, private parties cannot sue governmental
authorities because the governmental authority claims the benefit of what is
known as "sovereign immunity." P.M.I. Comercio Internacional has agreed in our
long term crude oil supply agreement, and PEMEX has agreed in our long term
crude oil supply agreement guarantee, not to claim, and has waived, any
immunity from suit or other legal process, subject to some limitations. There
can be no assurance, however, that either P.M.I. Comercio Internacional and/or
PEMEX will actually continue to do so in the future.
Environmental Risks
The Port Arthur refinery is located on a contaminated site. If the previous
owners and operators do not fulfill their remediation obligations, we may incur
substantial remediation costs.
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. The Port Arthur
refinery is located on a contaminated site. Under the 1994 purchase agreement
between Clark Refining & Marketing and Chevron Products USA relating to the
Port Arthur refinery, Chevron retained environmental remediation obligations
regarding pre-closing contamination at over 97% of the refinery site. Clark
Refining & Marketing assumed responsibility for any remediation that is
required in and under the remaining approximately 3% of the refinery site,
which consists of specified areas that extend 25 to 100 feet from active
operating units, including soil and groundwater, and, Clark Refining &
Marketing has estimated its liability for remediation of groundwater and soil
in these areas at $27 million. Chevron is obligated to remediate the
contamination in the areas for which it has retained responsibility as and when
required by law, in accordance with remediation plans negotiated by Chevron and
the applicable federal or state agencies.
22
<PAGE>
No part of our coker project site is located within the portion of the Port
Arthur refinery site for which Chevron retains environmental remediation
obligations. We have estimated remedial costs relating to our coker project
site, which encompasses less than 50 acres of the total Port Arthur refinery
site surface area, at $1.6 million. Clark Refining & Marketing has agreed to
retain liability regarding contamination existing at the coker project site and
has indemnified us against such liabilities. However, if Clark Refining &
Marketing does not fulfill its remediation obligations, we could incur
substantial additional costs in remediating the contamination, which could
impair our ability to make payments on the notes and our other debt when due.
Our failure to comply with existing and future environmental laws and
regulations could subject us to material liabilities or other sanctions.
Our operations are subject to numerous federal, state and local environmental
laws and regulations, such as those governing discharges to air and water, the
handling and disposal of solid and hazardous wastes and the remediation of
contamination. Although Clark Refining & Marketing has agreed in our services
and supply agreement to manage our heavy oil processing facility and to comply
at our cost with all applicable environmental laws and regulations, we cannot
guarantee you that this will always be the case. Any failure to comply with
these environmental requirements could subject us to, among other things, civil
liabilities, criminal penalties and the temporary or permanent shutdown of our
operations.
We cannot predict with certainty the future costs of environmental compliance
because of frequently changing compliance standards and technology. We expect
that future regulations or changes in existing environmental laws and
regulations or other interpretation may subject our operations to increasingly
stringent standards. Compliance with these requirements may make it necessary,
at costs that may be substantial, for us to undertake new measures in
connection with the storage, handling, transport, treatment or disposal of
hazardous materials, petroleum by-products and wastes and the remediation of
contamination. The costs of such actions could impair our financial condition,
results of operations or cash flows and accordingly could impair our ability to
make payments on the notes and our other debt when due.
Financing Risks
Our equity and debt funding sources may be inadequate and are subject to
extensive conditions precedent that may not be satisfied and may cause us to be
unable to pay our construction costs and our debt service obligations.
We expect initial funding commitments to be sufficient to pay amounts owing
to our contractors for the construction of our coker project and to fund all
other costs associated with developing, financing, constructing and
commissioning our coker project, including an allowance for contingencies.
However, we cannot assure you that no circumstances will arise that will
require additional funding beyond that for which we have obtained commitments.
You should also note that the equity commitments of our sponsors are limited to
approximately $122 million for Blackstone and approximately $13 million for
Occidental, and there is no other recourse to Blackstone or Occidental either
prior to or after completion of our coker project. In addition, drawdowns under
many of our funding commitments are subject to extensive conditions precedent,
including the absence of any material adverse changes. We cannot guarantee that
all the applicable conditions precedent for drawdowns under each of our funding
commitments will be satisfied at all times during or after the construction
period. Therefore, we may be unable to draw down these funds, which could cause
us to be unable to meet our payment obligations to our contractors and/or our
debt service obligations.
If we default on the notes after completion, your recourse will be limited to
the assets and cash flows of our coker project.
After completion of our coker project, our assets and cash flows from our
operations will be our sole source for repayment of the notes and our other
debt. Except for Sabine River and Neches River, no other owner or other
affiliate of us, including Clark Refining & Marketing, will be responsible for
making payments on the notes or will guarantee in any way the payment of the
notes. In the event that we default in our payment
23
<PAGE>
of amounts due on the notes, we cannot guarantee to you that the proceeds
realized upon a foreclosure and sale of our coker project will be sufficient
to pay amounts then outstanding on the notes. Thus, our ability to make
payments on the notes and our other debt when due will be entirely dependent
upon our ability to construct our coker project successfully and to operate in
a manner that provides sufficient cash flow to make payment on the notes and
our other debt when due.
The collateral securing the notes may be insufficient to pay amounts due on
the notes in the event of a foreclosure.
The outstanding notes are, and when issued the exchange notes will be,
secured by substantially all our assets and rights and other assets and rights
of other parties. You should note, however, that while the guarantee agreement
by which PEMEX has guaranteed the obligations of P.M.I. Comercio Internacional
under our long term crude oil supply agreement is part of the collateral, the
supply agreement between P.M.I. Comercio Internacional and Pemex Exploracion
is not part of the collateral securing the notes and other senior debt. In
addition, there may be limitations on our ability to create security interests
in some assets and rights or to legally protect your interest in some of the
collateral from claims by third parties. This is particularly true with
respect to security interests in governmental permits or technology licenses.
We cannot assure you that if we default on the notes and you foreclose on
and sell our assets you will receive proceeds to pay all amounts that we owe
you on the notes. Furthermore, your ability to foreclose on the collateral
will be subject to practical problems associated with the realization of the
security interests such as obtaining the requisite secured party consent to
foreclose on the collateral. We cannot assure you that your collateral trustee
will be able to realize upon the collateral without difficulty or delay or
that procedures implemented to support the validity and enforceability of
security interests will be sufficient. We cannot assure you that if you try to
foreclose on our assets, you will receive all the third-party approvals that
you need.
The collateral securing the notes is shared with our other senior secured
lenders, and this may cause the collateral to be an insufficient source from
which to pay amounts due on the notes.
We have substantial other senior secured indebtedness that ranks equally and
ratably with the notes and is entitled to the benefits of a common security
package. Our other senior secured indebtedness includes the following:
. a construction and term loan facility of $325 million;
. working capital facilities of up to $75 million; and
. reimbursement obligations of up to $150 million, resulting from payments
under the guaranty insurance policy relating to our payment obligations
under our long term crude oil supply agreement.
The collateral provided for your benefit will be shared, on an equal and
ratable basis, with the other senior secured parties. You will share control
over enforcement of the common security package with all the other senior
lenders. In specified circumstances, the direction of a specified percentage
of all of the senior lenders, including you, will be required to initiate
foreclosure and you should not expect that the noteholders in those
circumstances will themselves constitute the required percentage for control
of that action.
For a substantial period during which the notes will be outstanding, amounts
due to other senior secured parties will also remain outstanding and be
secured by the same collateral and our total outstanding senior secured
indebtedness could be as much as $805 million. We cannot assure you that, upon
the occurrence of an event of default and acceleration, the exercise of
remedies, including foreclosing on the collateral, would provide funds
sufficient to pay all or even a substantial portion of the outstanding
principal and accrued interest on the notes as well as all amounts due to the
other secured parties. Events of default include failure to pay interest,
principal or fees when due, the falsity of representations and warranties that
we made in connection with the financing, breach of any of our covenants,
which include covenants relating to timely completion of
24
<PAGE>
our coker project, preservation of our existence, and not amending our project
documents, mis-application of funds, cross-defaults to our other financing
documents and to the long term oil supply agreement, the hydrogen supply
contract and our other project documents, insolvency of ourselves, Sabine
River, Neches River or, prior to completion of our coker project, Blackstone,
and failure of Clark Refining & Marketing or Air Products to complete their
portions of the refinery upgrade project.
We may incur additional debt, which may reduce the benefits of the collateral.
Subject to the limitations set forth in the common security agreement, we are
permitted to incur additional indebtedness. This additional indebtedness may
rank equally with the notes and share ratably in the collateral that secures
the notes and thus may increase the risk that we will be unable to make
payments on the notes and our other debt when due. This may reduce the benefits
of the collateral to you and your ability to control all actions taken with
respect to the collateral.
There is no existing market for the exchange notes, and we cannot assure you
that an active trading market will develop for the exchange notes or that you
will be able to sell your exchange notes.
There is no existing market for the exchange notes, and there can be no
assurance as to the liquidity of any markets that may develop for the exchange
notes, your ability to sell your exchange notes or the prices at which you
would be able to sell your exchange notes. Future trading prices of the
exchange notes will depend on many factors, including, among other things,
prevailing interest rates, our operating results and the market for similar
securities. The initial purchasers of the outstanding notes are not obligated
to make a market in the exchange notes and any market making by them may be
discontinued at any time without notice. We do not intend to apply for a
listing of the exchange notes on any securities exchange or on any automated
dealer quotation system.
Historically, the market for non-investment grade debt has been subject to
disruptions that have caused volatility in prices. It is possible that the
market for the exchange notes will be subject to disruptions. Any such
disruptions may have a negative effect on you, as a holder of the exchange
notes, regardless of our prospects and financial performance.
If you choose not to exchange your outstanding notes, the present transfer
restrictions will remain in force and the market price of your outstanding
notes could decline.
If you do not exchange your outstanding notes for exchange notes under the
exchange offer, then you will continue to be subject to the transfer
restrictions on the outstanding notes as set forth in the prospectus
distributed in connection with the offering of the outstanding notes. In
general, the outstanding notes may not be offered or sold unless they are
registered or exempt from registration under the Securities Act and applicable
state securities laws. Except as required by the registration rights agreement,
we do not intend to register resales of the outstanding notes under the
Securities Act. You should refer to "Prospectus Summary --Summary of the
Exchange Offer" and "The Exchange Offer" for information about how to tender
your outstanding notes.
The tender of outstanding notes under the exchange offer will reduce the
principal amount of the outstanding notes outstanding, which may have an
adverse effect upon, and increase the volatility of, the market price of the
outstanding notes due to a reduction in liquidity.
25
<PAGE>
USE OF PROCEEDS
Port Arthur Finance will not receive any cash proceeds from the issuance of
the exchange notes. In consideration for issuing the exchange notes as
contemplated in this prospectus, Port Arthur Finance will receive in exchange a
like principal amount of outstanding notes, the terms of which are identical in
all material respects to the exchange notes. The outstanding notes surrendered
in exchange for the exchange notes will be retired and canceled and cannot be
reissued. Accordingly, issuance of the exchange notes will not result in any
change in the capitalization of Port Arthur Finance. See "Financing Plan" for a
discussion of the use of proceeds from the sale of the outstanding notes.
26
<PAGE>
FINANCING PLAN
We estimate that the total costs for our coker project will be approximately
$715 million. Our sources of funds are described as follows.
Equity Contributions and Commitments
Blackstone and Occidental have agreed to make capital contributions in an
aggregate maximum amount of approximately $135 million under capital
contribution agreements. The lenders of our senior debt have the right to
enforce the obligations of Blackstone and Occidental to make capital
contributions under these agreements.
Under these capital contribution agreements, when we issued the outstanding
notes Blackstone and Occidental made initial equity contributions in the
aggregate amount of $20 million which flowed down through our ownership
structure to us and have made approximately $41 million in additional equity
contributions since such time, bringing the total to approximately $61 million
as of February 29, 2000. During the remaining construction period, Blackstone
will make additional periodic equity contributions of approximately $66 million
and Occidental will make approximately $8 million in additional equity
contributions. These additional equity contributions will be made on a ratable
basis with drawings under the secured construction and term loan facility
described below to pay for construction costs and will flow down through our
ownership structure to us. Under these capital contribution agreements, if
Blackstone or Occidental is excused by operation of law in a bankruptcy
proceeding of us, either Sabine River, Neches River or Clark Refining Holdings
or, for any other reason, Blackstone and Occidental, will be required either to
make subordinated loans to us or to purchase subordinate participations in the
senior debt, in either case in the amounts of their individual capital
contribution commitments.
Outstanding Notes and Existing Bank Credit Facilities
Approximately $580 million of the budgeted cost of developing, financing and
constructing our coker project is being funded with senior debt. Our senior
debt consists of $255 million from the sale of the outstanding notes and $325
million from borrowings under the bank credit facilities described below.
When we issued the outstanding notes, we also entered into a construction and
term loan agreement with a syndicate of lenders establishing a secured
construction and term loan facility. The construction and term loan facility is
split into a Tranche A of $225 million and a Tranche B of $100 million, with
Tranche A loans having a term of 7.5 years and Tranche B loans having a term of
8 years. Under specified circumstances, the aggregate amount of the
construction and term loan facility may be reallocated between the tranches
with our consent, which may not be unreasonably withheld. In November 1999, the
lenders under our construction and term loan facility requested that we
reallocate $5 million from Tranche A to Tranche B. At the time our construction
and term loan facility closed, the bank arrangers intended to reduce their
commitment exposure to us by syndicating their commitments with other banks. We
agreed that if necessary in order to complete the syndication of the
construction and term loan facility, the bank arrangers with our consent, which
may not be unreasonably withheld, may increase the interest rate margins on the
construction and term loan facility upon a reaffirmation from Moody's and
Standard & Poor's of our then-current rating after giving effect to such
increase.
We also obtained a secured working capital facility of up to $75 million with
a term of up to 7.5 years at the time the outstanding notes were issued. Any
portion of the secured working capital facility that is advanced as loans will
bear interest at an annual rate of LIBOR plus 4.75% or at a prime rate plus
3.75%, at our election. We are required to pay fees on any letters of credit
issued under the secured working capital facility equal to an annual rate of
LIBOR plus 4.75%, plus an annual facing fee of 0.15%. We also pay commitment
fees on the unutilized portion of the construction and term loan facility equal
to 0.75% per annum and on the unutilized portion of the secured working capital
facility equal to 0.50% per annum. In February 2000, our $75 million secured
working capital facility was reduced to $35 million. The $40 million reduction,
a portion of which had been outstanding in the form of a letter of credit to
P.M.I. Comercio Internacional to secure against a default by us under our long
term oil supply agreement, was replaced by an insurance policy under which an
affiliate of American International Group agreed to insure P.M.I. Comercio
Internacional against our default under the
27
<PAGE>
long term oil supply agreement up to a maximum liability of $40 million. This
affiliate of American International Group is treated as a bank senior lender
under the common security agreement.
Port Arthur Finance transferred the net proceeds of the offering of the
outstanding notes to Port Arthur Coker Company by means of an intercompany note
and will transfer the proceeds of drawings under the bank credit facilities to
Port Arthur Coker Company by means of the intercompany note. Port Arthur Coker
Company has, or will, use such proceeds principally to pay part of the costs of
our coker project and related items, including:
. amounts payable under our construction contract;
. other asset acquisition costs;
. initial start-up costs and working capital requirements;
. financing costs, legal and other transaction costs, taxes and interest
during construction;
. other costs and expenses associated with our coker project; and
. establishment of a construction contingency fund.
The net proceeds from the sale of the outstanding notes, after deducting
discounts offered to the initial purchasers and related transaction expenses
payable, was approximately $244 million.
Winterthur Insurance Policies
Winterthur, on behalf of a group of insurers, arranged a $150 million oil
payment guaranty insurance policy to provide payment security for crude oil
purchases by us from P.M.I. Comercio Internacional.
In order to accommodate a financing structure that includes the bank credit
facilities, the Winterthur oil payment guaranty insurance policy and the notes,
we have entered into a common security agreement which contains, among other
things, common covenants, representations and warranties, events of default and
remedies applicable to all our senior debt and reimbursement obligations to
Winterthur relating to its oil payment guaranty insurance policy, including the
notes and any loans made under our bank credit facilities. The terms of the
common security agreement are discussed under the heading "Description of Our
Principal Financing Documents--Common Security Agreement" in this prospectus.
28
<PAGE>
The following table sets forth the estimated sources and uses of funds in
connection with the development, construction and financing of our coker
project through completion and commercial operation of our heavy oil processing
facility, including the notes. We cannot assure you that these estimates will
correspond to the actual uses of funds to complete our coker project. Proceeds
from the sale of the outstanding notes were deposited into an account called
the bond proceeds account and must be applied in accordance with the financing
documents. As required under our construction and term loan facility, the
entire amount of Tranche B loans were drawndown in October 1999 and $35.4
million of additional equity was contributed by Blackstone and Occidental.
These amounts were deposited into an account called the bank loan drawdown and
equity funding account and will be applied in accordance with the financing
documents. You should read the section captioned "Description of Our Principal
Financing Documents--Common Security Agreement--Account Structure" in this
prospectus for more information regarding the accounts we are required to
maintain and fund and regarding restrictions on our ability to use funds from
these accounts.
<TABLE>
<CAPTION>
Amounts
------------------------
(in millions of dollars)
<S> <C> <C>
Sources
Construction and term loans................ $325 45.5%
The notes.................................. 255 35.6
Equity contributions(1).................... 135 18.9
---- -----
Total Sources................................ $715 100.0%
==== =====
Uses
Construction contract(2)................... $544 76.1%
Coker project contingency.................. 28 3.9
Net interest during construction........... 89 12.5
Start-up, development, asset acquisition
and other construction costs(3)........... 22 3.1
Financing costs, legal and other
transaction costs(4)...................... 32 4.4
---- -----
Total Uses................................... $715 100.0%
==== =====
</TABLE>
- --------
(1) Consists of cash equity contributions by Blackstone and Occidental
described under "--Equity Contributions and Commitments" above.
(2) Includes payment to Clark Refining & Marketing for work in progress related
to our coker project.
(3) Includes compensation of approximately $2 million to Clark Refining &
Marketing for other assets transferred to us, including our long term crude
oil supply agreement.
(4) Includes discounts offered, and fees and expenses payable to the initial
purchasers and other related expenses, legal services and printing costs.
Interest expense during construction, net of interest income was calculated
in the Purvin & Gertz base case model using the expected construction timeline,
related funding requirements and interest rates of 12.50% on the outstanding
notes and 10.75% construction and term loan facility.
We believe that the proceeds of the sale of the outstanding notes, equity
contributions and monies borrowed under our construction and term loan facility
will provide sufficient funds to develop, construct and finance our coker
project.
29
<PAGE>
CAPITALIZATION
The following table sets forth the capitalization of Port Arthur Coker
Company as of December 31, 1999, and as adjusted to give effect to the issuance
and sale of the outstanding notes and the initial equity contributions, and the
application of the estimated proceeds from these sources as described under
"Use of Proceeds." The following table should be read in conjunction with our
selected financial information included under "Selected Financial Information"
and the base case financial model included in Purvin & Gertz's Independent
Engineer's Report which is Annex B to this prospectus.
<TABLE>
<CAPTION>
December 31,
1999
--------------
(in thousands)
<S> <C>
Construction and Term Loans...................................... $105,000
Notes............................................................ 255,000
--------
Total Senior Debt.............................................. 360,000
Equity Contributions........................................... 57,120
--------
Total Capitalization......................................... $417,120
========
</TABLE>
30
<PAGE>
SELECTED FINANCIAL INFORMATION
The following selected financial information should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition."
Port Arthur Coker Company and Subsidiary
The selected financial data presented below for Port Arthur Coker Company and
its subsidiary represents our consolidated balance sheet as of December 31,
1999 and statement of operations for the period from inception, May 4, 1999, to
December 31, 1999, and is derived from audited financial statements included
elsewhere in this prospectus. We are in our development stage. Accordingly,
only balance sheet and statement of operations data is presented, and no ratio
of earnings to fixed charges is presented. This table should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition"
and the consolidated financial statements and related notes included elsewhere
in this prospectus.
<TABLE>
<CAPTION>
December 31,
1999
------------------
Consolidated Balance Sheet (in thousands)
<S> <C>
Assets
Cash....................................................... $ 1
Receivable from affiliate.................................. 90
Prepaid expenses........................................... 845
--------
Total current assets..................................... 936
Construction in progress................................... 378,411
Cash and cash equivalents restricted for capital additions. 46,657
Other assets............................................... 20,575
--------
$446,579
========
Liabilities and Partners' Capital
Accounts payable........................................... $ 28,145
Accrued expenses and other................................. 14,721
Payables with affiliates................................... 497
--------
Total current liabilities................................ 43,363
Long-term debt............................................. 360,000
Commitments and contingencies.............................. --
Partners' capital contributed.............................. 57,120
Deficit accumulated during development stage............... (13,904)
--------
$446,579
========
<CAPTION>
For the period
May 4, (inception)
to December 31,
1999
------------------
(in thousands)
<S> <C>
Consolidated Statement of Operations
General and administrative expenses........................ $ (3,149)
Interest and finance costs, net............................ (10,755)
--------
Net loss................................................... $(13,904)
========
</TABLE>
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<PAGE>
Port Arthur Finance Corp.
We have not included in this prospectus separate financial information for
Port Arthur Finance, however, the consolidated financial statements for Port
Arthur Coker Company include Port Arthur Finance as a consolidated subsidiary.
Its organizational documents do not permit it to engage in any activity other
than issuing the notes and borrowing under our bank credit facilities, and
remitting the proceeds thereof to Port Arthur Coker Company. Port Arthur
Finance has no material assets, no liabilities and no operations. In issuing
the notes and borrowing under our bank credit facilities, it is acting as an
agent of Port Arthur Coker Company.
Sabine River Holding Corp.
We have included elsewhere in this prospectus separate audited financial
statements for Sabine River. Its organizational documents do not permit it to
engage in any activity other than issuing its guarantee of the notes and the
bank loans, acting as a partner of Port Arthur Coker Company, acting as 100%
owner of Neches River and taking any other actions necessary in connection with
the transactions described in this prospectus. Sabine River has no material
assets, no liabilities and no operations other than its investment in PACC and
Neches River.
Neches River Holding Corp.
We have not included in this prospectus separate financial information for
Neches River. Its organizational documents do not permit it to engage in any
activity other than issuing its guarantee of the notes and the bank loans,
acting as a partner of Port Arthur Coker Company and taking any other actions
necessary in connection with the transactions described in this prospectus.
Neches River has no material assets, no liabilities and no operations other
than its investment in PACC.
32
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
The following discussion should be read in conjunction with "Financial
Statements and Related Notes for Port Arthur Coker Company and Sabine River,"
"Selected Financial Information," "Annex B--Independent Engineer's Report" and
"Annex C--Crude Oil and Refined Products Market Report."
General
We were formed to construct, own or lease, operate and maintain our heavy oil
processing facility. Since our inception, we have been in the pre-operation
stage and have had no material operating revenues or expenses. The total cost
to us of our coker project, including development, property acquisitions,
construction, capitalized interest, testing and start-up, is estimated to be
approximately $715 million, including allowance for estimated price escalation
and contingencies. Our notes are unconditionally guaranteed jointly and
severally by Port Arthur Coker Company, Sabine River and Neches River. Sabine
River and Neches River, however, have no material assets, no liabilities and no
operations other than their investment in Port Arthur Coker Company.
Operations to Date
Clark Refining & Marketing formally initiated the refinery upgrade project in
April 1998 after entering into the long term crude oil supply agreement with
P.M.I. Comercio Internacional in March 1998. Construction began in September
1998. When we issued the outstanding notes, Clark Refining & Marketing assigned
to us all its rights and obligations under the long term crude oil supply
agreement, including the obligation to complete the refinery upgrade project,
and permits related to operating our new and leased units and we purchased the
work in progress relating to our coker project for a total of approximately
$159 million.
The work on our coker project is well advanced. As of January 2000, 100% of
major equipment procurement, 89% of total materials procurement and 98% of
detailed design and engineering were complete and construction was 31%
complete. Construction activities to date have included site preparation,
foundations and footings installation, major equipment installation and pipe
rack construction. In June 1999, the six coke drums for our new delayed coking
unit arrived at the Port Arthur refinery and in October 1999 were installed in
their support structures. In January 2000, approximately 175 people were
working on design and engineering and approximately 965 people are working on
construction of our coker project. All personnel except one are employees of
Foster Wheeler USA, its subcontractors or Clark Refining & Marketing, the
latter working under our services and supply agreement with Clark Refining &
Marketing.
Under our construction contract, Foster Wheeler USA is obligated to perform
the engineering, design, procurement, manufacture, construction, erection,
installation and testing of our coker project. Under the construction contract,
we are required to pay Foster Wheeler USA the fixed sum of approximately $544
million in installments to be based on their progress in completing our coker
project. This payment to Foster Wheeler USA has been reduced by $157.1 million,
the amount Clark Refining & Marketing had already paid Foster Wheeler USA for
work performed to date on our coker project.
When we issued the outstanding notes, we used a portion of the proceeds of
our senior debt and equity contributions to make the following payments to
Clark Refining & Marketing:
<TABLE>
<S> <C>
Payment for work in progress related to our coker project--con-
struction contract............................................... $157,100,000
Payment for permits and the long term crude oil supply agreement.. 2,175,000
------------
Total........................................................... $159,275,000
============
</TABLE>
Plan of Operation
The refinery upgrade project will allow our heavy oil processing facility to
process an average of 200,000 barrels per stream day of crude oil. At least
150,000 barrels per stream day of heavy sour crude oil will be purchased from
P.M.I. Comercio Internacional under our long term crude oil supply agreement.
Construction of our coker project and the entire refinery upgrade project is
expected to be mechanically complete around November 2000, and we expect to
begin commercial operation around January 2001.
33
<PAGE>
Our long term crude oil supply agreement includes a mechanism designed to
minimize the effect of adverse refining cycles and to moderate the fluctuations
of our coker gross margin. This mechanism contains a formula that is intended
to be an approximation for coker gross margin and is designed to provide for a
minimum average coker gross margin over the first eight years following
completion of the refinery upgrade project, if it is completed by July 2001.
This eight year period will be shortened by any period of delay in completion
of the refinery upgrade project beyond July 2001 unless the delay is caused by
events beyond our reasonable control.
Clark Refining & Marketing has agreed to provide us with services necessary
to complete our coker project and to operate the heavy oil processing facility.
Under our services and supply agreement, the services to be performed by Clark
Refining & Marketing include, among others, the following:
. oversight of the construction of our new units and other equipment and
performance of our obligations under our construction contract with
Foster Wheeler USA, other than our payment obligations;
. operation and maintenance of the ancillary units and equipment that we
are leasing from Clark Refining & Marketing;
. management of the operation and maintenance of our new processing units
and other equipment at the Port Arthur refinery;
. management of our crude oil purchases and transportation of our crude
oil to the Port Arthur refinery; and
. supply of other required feedstocks, materials and utilities.
However, Sabine River's board of directors controls the ultimate decision
making, and guides the ongoing activities, of Port Arthur Coker Company.
In addition, under our services and supply agreement Clark Refining &
Marketing has a right of first refusal to require us to process crude oil for
them in an amount equal to approximately 20% of the processing capacity of our
heavy oil processing facility. In exchange, we will receive processing fees
from Clark Refining & Marketing.
We have entered into a product purchase agreement with Clark Refining &
Marketing for the sale of all refined and intermediate products produced by our
heavy oil processing facility. Under our product purchase agreement, Clark
Refining & Marketing is obligated to accept and pay for all our products and
has a limited right to request that we produce a specified mix of products.
Purvin & Gertz expects us to generate approximately $228 million of annual
average operating cash flows over the initial 11-year operating period of our
coker project.
Liquidity and Capital Resources
Prior to the completion and commercial operation of our heavy oil processing
facility, we expect that the cash available to us will consist principally of
equity contributions of up to $135 million, proceeds from the offering of the
outstanding notes of $255 million and up to $325 million in proceeds from
borrowings under our bank credit facilities, together with interest earnings on
those amounts. The contractual arrangements with Blackstone and Occidental
provide that the aggregate $135 million equity commitment will be funded pro
rata with the funding of our notes and bank term debt, so that at the time of
each advance of debt and equity to pay our construction costs, the amount
funded will be approximately 65% debt and 35% equity. As of December 31, 1999,
$57 million of the $135 million of equity had been funded. We expect the
remaining $78 million of equity to be funded by March 2001. We believe that
these amounts are sufficient to fund the development, construction and
financing costs of our coker project.
During the operating period, our revenues will include revenues from sales of
products to Clark Refining & Marketing under the product purchase agreement and
processing fees paid by Clark Refining & Marketing under the services and
supply agreement. We have a working capital facility of up to $35 million from
a
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<PAGE>
syndicate of lenders, some of which are the same commercial banks that are
providing the construction and term loan facility. The proceeds of any
borrowing under this working capital facility will be used primarily for
issuing letters of credit for purchase of crude oil other than Maya and to meet
our other working capital needs. In February 2000, our working capital facility
was reduced from $75 million to $35 million. The $40 million reduction, a
portion of which had been outstanding in the form of a letter of credit to
P.M.I. Comercio Internacional to secure against a default by us under our long
term oil supply agreement, was replaced by an insurance policy under which an
affiliate of American International Group agreed to insure P.M.I. Comercio
Internacional against our default under the long term oil supply agreement up
to a maximum liability of $40 million.
In order to fulfill our obligation to provide security to P.M.I. Comercio
Internacional for our obligation to pay for shipments of Maya under the long
term crude oil supply agreement, we obtained from Winterthur an oil payment
guaranty insurance policy for the benefit of P.M.I. Comercio Internacional.
This oil payment guaranty insurance policy is in the amount of up to $150
million and will be a source of payment to P.M.I. Comercio Internacional if we
failed to pay P.M.I. Comercio Internacional for one or more shipments of Maya.
Under our senior debt documents, any payments by Winterthur on this policy are
required to be reimbursed by us. This reimbursement obligation to Winterthur
has a priority claim on all of the collateral for the senior debt equal to the
noteholders and holders of our other senior debt, except in specified
circumstances in which it has a senior claim to these parties. We describe
these priorities in greater detail in our description of the Intercreditor
Agreement under "Description of Our Principal Financing Documents--Guaranty
Insurance Policy and Reimbursement Agreement."
Under our senior debt documents, we are also required to establish a debt
service reserve account at the time our coker project achieves substantial
reliability in an amount equal to the next semiannual payment of principal and
interest coming due from time to time. Substantial reliability is a term in our
construction contract and our financing documents that is used to indicate when
Foster Wheeler USA has demonstrated that our coker project is sufficiently
complete and can reliably generate expected operating margins. A more detailed
description of substantial reliability can be found under the heading
"Principal Project Documents--Construction Contract--Performance Testing and
Guarantees" in this prospectus. In lieu of depositing funds into this reserve
account at substantial reliability, we have 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 our coker project. Payments will be made under this policy to pay debt
service to the extent that 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. The term of the policy commences at substantial reliability of
our coker project and ends on the tenth semiannual payment date after
substantial reliability, unless it terminates early because our debt service
reserve account is funded to the required amount. The maximum liability of
Winterthur under its policy is reduced as we make 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, we are
required to deposit, out of available funds for that purpose, $12 million into
the debt service reserve account. In addition, until the debt service reserve
account contains the required amount, we are required to make deposits into the
debt service reserve account equal to all of our excess cash flow that remains
after we apply 75% of excess cash flow to prepay senior debt. Once the debt
service reserve account contains the required amount, the Winterthur policy
will terminate.
When we issued the outstanding notes, we obtained business interruption and
contingent business interruption insurance for our heavy oil processing
facility.
We may also incur additional senior debt or subordinated debt provided that
it complies with the terms and conditions set forth in the common security
agreement.
Accounts
The common security agreement requires that all of our bank accounts, with
the exception of an unsecured account for up to 30 days' operating costs, be
secured for the benefit of our senior lenders, including you. We
35
<PAGE>
are required to maintain separate accounts for specified purposes. Deposits and
withdrawals from these accounts may only be made in accordance with the terms
of our financing documents that specify the order in which our revenues are
applied and the order in which our expenses are paid. We describe these
accounts, and the maximum amounts required to be deposited in them, in greater
detail under "Description of Our Principal Financing Documents--Common Security
Agreement--Account Structure."
Quantitative and Qualitative Disclosures About Market Risk
From time to time, we expect to hold market risk sensitive instruments and
positions, such as our inventory of crude oil and refined products. The market
risk inherent in our market risk sensitive instruments and positions is the
potential loss from adverse changes in commodity prices and interest rates.
None of our market risk sensitive instruments are held for speculative trading.
Commodity Risk
Our feedstocks and refined products are principally commodities and the
pricing of such feedstocks and refined products under our services and supply
agreement and product purchase agreement is intended to reflect market-based
pricing. As a result, our operating cash flows and earnings will be
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, the rate of industry investments, the availability of imports, the
marketing of competitive fuels and the extent of government regulations.
Purvin & Gertz, the independent engineer, has set forth in its Independent
Engineer's Report annexed to this prospectus as Annex B, an analysis of the
impact of the changes in prices of crude oil and refined products on our
operating cash flow. We believe that their analysis has been made on a
reasonable basis.
We expect to utilize limited risk management tools to mitigate risk
associated with fluctuations in petroleum prices on our normal operating
petroleum inventories. We believe this policy is appropriate since inventories
are required to operate the business and are intended to be owned for an
extended period of time. We believe the cost of using such tools to manage
short-term fluctuations outweigh the benefits. In addition, the common security
agreement limits our ability to use those tools.
We may occasionally use strategies to minimize the impact on profitability of
volatility in feedstock costs and refined product prices. These strategies will
generally involve the purchase and sale of exchange-traded, energy-related
futures and options with a duration of six months or less. In addition, we, to
a lesser extent, may use energy swap agreements similar to those traded on the
exchanges, such as crack spreads and crude oil options, to better match the
specific price movements in our markets as opposed to the delivery point of the
exchange-traded contract. These strategies are designed to minimize, on a
short-term basis, our exposure to fluctuations in refining margins. The number
of barrels of crude oil and refined products covered by such contracts will
vary from time to time. These purchases and sales will be closely managed and
be subject to internally established risk standards. The results of these
hedging activities will affect refining costs of sales. We do not intend to
engage in speculative futures or derivative transactions.
Interest Rate Risk
Our long term debt will be subject to interest rate risk. We will manage this
rate risk by maintaining a mix of long term debt with fixed and floating rates.
A 1% change in the interest rate on our long term debt could result in a $5.8
million change in earnings before interest and taxes. This determination is
based on 1% of the $580 million total of the notes and the construction and
term loans. We will be subject to interest rate risk on the floating rate bank
term debt, but we will have the ability to call our floating rate debt. Under
the common security agreement we may be required to hedge a substantial portion
of our floating rate exposure under our secured construction and term loan
facility.
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<PAGE>
Year 2000 Readiness
As has been widely reported, many computer systems process dates based on two
digits for the year of a transaction and many feared that computers would be
unable to process dates in the year 2000 and beyond. There were many risks
associated with the year 2000 compliance issue, including but not limited to,
the possible failure of our systems and hardware with embedded applications.
The failure of third parties, including our contractors, vendors, utilities
and customers to remedy year 2000 issues also posed risks to our coker project.
In particular, any failures by (1) Clark Refining & Marketing, which will be
responsible for the management of our heavy oil processing facility and will
purchase all our refined products, (2) Foster Wheeler USA, as contractor under
the construction contract or (3) P.M.I. Comercio Internacional, as our
principal supplier of oil, may have a material adverse effect on our businesses
and operations.
Clark Refining & Marketing began significant efforts to address its exposures
related to the year 2000 issue in 1997 in order to operate and properly process
information after December 31, 1999. Clark Refining & Marketing has expended
$5.9 million from inception of its year 2000 systems remediation program
through December 31, 1999. Clark Refining & Marketing believes that as of
October 1999 its mission critical embedded processors at refineries and mission
critical systems, including hardware and software, were ready for the year
2000. In addition, its mission critical business partners had represented that
their mission critical systems were remediated. As of January 31, 2000, Clark
Refining & Marketing had incurred only minor year 2000-related problems with
its mission critical systems or processes and contingency plans handled these
occurrences. More information on Clark Refining & Marketing's year 2000 program
is discussed in Clark Refining & Marketing's Annual Report on Form 10-K/A for
the year ended December 31, 1998 and Quarterly Report on Form 10-Q for the
period ended September 30, 1999, as amended.
The following information concerning Foster Wheeler Corporation is based
solely on and derived solely from their annual report on Form 10-K for the year
ended December 31, 1998, and their quarterly report on Form 10-Q for the third
quarter of 1999, filed with the Commission. We have not conducted any
independent investigation in this regard and therefore cannot assure the
accuracy or completeness of such information.
Foster Wheeler Corporation and its subsidiaries initiated year 2000
activities in 1996. In 1997, a formal year 2000 problem management strategy was
prepared. The primary computerized reporting and control system used by Foster
Wheeler Corporation and most of its subsidiaries, which was provided by J.D.
Edwards, has been confirmed by the vendor to be year 2000 compliant. Although
Foster Wheeler Corporation and its subsidiaries expect to be ready to continue
their business activities without interruption by a year 2000 problem, they
recognize that they depend on outsiders (such as suppliers, contractors and
utility companies) to provide various goods and services necessary for doing
business. Foster Wheeler Corporation has developed a contingency plan for
itself, and has required each of its subsidiaries to do likewise. Each plan
will address alternative arrangements to cope with year 2000 problems caused by
others, and back-up strategies to follow if a subsidiary's software or
equipment does not perform properly, even though it appears now to be year 2000
compliant. Most subsidiaries of Foster Wheeler Corporation completed their
contingency plans by late September 1999 and the few that did not were expected
to complete their plans by the end of November 1999. The failure to correct a
year 2000 problem could result in an interruption in, or a failure of, certain
normal business activities or operations. Foster Wheeler Corporation believes
that the implementation of new business systems and the complete implementation
of the business continuation plan should reduce the possibility of significant
interruptions of normal operation.
As of February 18, 2000, we have not had any material impact on our coker
project related to the year 2000 issue and we have not been made aware of any
material impact on Clark Refining & Marketing, Foster Wheeler USA, P.M.I.
Comercio Internacional or any other third parties associated with the refinery
upgrade project. We anticipate that our future year 2000 related costs will not
have a material impact on our financial position or results of operations. See
"Risk Factors--Construction Risks."
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<PAGE>
THE U.S. PETROLEUM REFINING INDUSTRY AND REFINERY CONFIGURATION
Background
The profitability of an oil refinery is determined, in large part, by
refining margins, the spread between prices for refined products such as
gasoline, diesel fuel and jet fuel, and costs of crude oil. The refining margin
is driven by the supply and demand for petroleum commodities. Refinery
profitability is also influenced by the equipment configuration of the
refinery, the refinery's operating cost structure and the refinery's access to
crude oil and refined product markets.
Demand for light refined products such as gasoline, diesel, kerosene/jet fuel
grew at an annual rate of 4.2% from 1960 to 1973, according to the U.S.
Department of Energy. However, demand for light refined products declined by
0.5% per year from 1973 to 1983. We believe that the combination of high oil
prices for petroleum products due to the oil shocks of the early 1970's and the
late 1970's, environmental regulations favoring cleaner burning fuels and gains
in fuel efficiency caused consumption of light refined products to decrease.
From 1983 through 1998, light refined product demand increased at a rate of
1.6% per year and, from 1993 through 1998, at 2.1% per year. We believe the
renewed growth in light refined product demand is due to the expansion of U.S.
vehicle fleet miles driven, increased seat miles flown on U.S. airlines and the
reduced improvement in vehicle fuel efficiency due to consumer preference for
light trucks and sport-utility vehicles.
Demand for heavy refined products such as residual and other heavy oil grew
at an annual rate of 4.0% from 1960 to 1978, according to the U.S. Department
of Energy. We believe that the introduction of regulations restricting the use
of residual oil in the late 1970's drastically reduced demand for residual oil,
as demand decreased from approximately 3 million barrels per day in 1978 to
approximately 0.9 million barrels per day in 1998, an annual decrease of 5.9%.
During this same period, overall heavy refined product demand has decreased at
only approximately 1% per year.
From 1965 through 1978, crude oil distillation capacity utilization rates
averaged approximately 89%, according to the American Petroleum Institute. We
believe that sagging demand for light and heavy refined products was the
primary cause that utilization rates fell to 69% in 1981. U.S. crude oil
distillation capacity decreased from 18.1 million barrels per day in 1980 to
15.9 million barrels per day in 1998, according to the Oil & Gas Journal, as
more than 40% of the refineries in the United States closed during this period.
As a result of this decrease in capacity and the renewed increase in demand,
U.S. crude oil distillation utilization rates increased during the 1980s and
1990s to approximately 95% in 1998. We believe U.S. crude oil distillation
utilization rates may be approaching long term sustainable maximums due to the
requirement for routine maintenance and the likelihood of unplanned downtime.
U.S. Industry Outlook
Purvin & Gertz expects annual growth in refined product demand in the U.S. to
average over 1.2% through 2015. Purvin & Gertz further expects that growth in
overall distillate in the United States will average near 2% over the next
decade, before slowing to about 1.5% through the 2010 to 2015 period and
gasoline demand growth will average 1% through 2015. We believe this growth
reflects the continuing expansion of U.S. vehicle fleet miles driven, increased
seat-miles flown on U.S. airlines with an offset for modest improvements in
vehicle efficiency.
Purvin & Gertz expects that total vehicle miles in the United States will
increase by approximately 2.7% per year until the end of the decade.
Thereafter, Purvin & Gertz expects growth in vehicle miles to average in the
1.7% range through 2015. Purvin & Gertz expects in the United States demand per
capita for gasoline to decrease over the forecasted period largely as a result
of efficiency improvement and continuing increases in per capita miles
traveled. Purvin & Gertz forecasts that between 1998 and 2015 new car
efficiency will improve by 5.3 miles per gallon.
Purvin & Gertz also expects diesel and jet fuel demand to exhibit the
strongest light refined product demand growth with 2% per year growth
throughout the next decade. Purvin & Gertz expects demand for
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residual fuel in the United States to continue declining trends throughout the
next decade and demand for all other petroleum products, including other
refined products and natural gas liquids, to increase at a rate of
approximately 1.1% during the next 15 years.
The following table summarizes the historical and expected growth patterns in
demand for refined petroleum products in the United States.
U.S. Petroleum Product Demand
<TABLE>
<CAPTION>
Annual %
Change
1995 1996 1997 1998 1999 2000 2005 2010 2015 1998-2015
----- ----- ----- ----- ----- ----- ----- ----- ----- ---------
(barrels in millions per day)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Motor Gasoline.......... 7.79 7.89 8.02 8.20 8.39 8.51 8.89 9.42 9.68 1.0%
Kerosene/Jet Fuel....... 1.55 1.64 1.66 1.65 1.70 1.74 1.94 2.13 2.31 2.0%
Diesel Fuel............. 3.21 3.37 3.44 3.44 3.55 3.65 4.03 4.43 4.83 2.0%
Residual Fuel........... 0.85 0.85 0.80 0.82 0.81 0.81 0.78 0.76 0.75 (0.5)%
Other Products.......... 4.33 4.56 4.71 4.57 4.58 4.63 5.01 5.27 5.49 1.1%
----- ----- ----- ----- ----- ----- ----- ----- ----- ----
Total U.S. Demand..... 17.72 18.30 18.62 18.68 19.03 19.35 20.64 22.01 23.06 1.3%
Annual Growth, %........ 0.0% 3.3% 1.7% 0.3% 1.9% 1.7% 1.3% 1.3% 0.9%
Source: Purvin & Gertz.
</TABLE>
Refinery Configurations
Crude oil represents a refinery's largest single operating cost and is
available in a range of prices depending on the equipment required for
processing the crude oil, its potential yield of refined products, and the cost
of transporting the crude oil to the refinery. Lighter and/or sweeter crude oil
is priced higher than heavy and/or sour crude oil because it is easier to
process and yields a higher-valued mix of products such as gasoline, diesel
fuel, jet fuel and petrochemicals.
The types of crude oil a refinery can process, as well as the yield of
refined products from such crude oil, depends on the refinery "configuration."
The configuration of a refinery denotes the number, specific types and the
sequence of processing units. Processing units typically increase the value of
their feedstocks by separating or changing the feedstocks' chemical structure.
A refinery with a simple configuration chooses between running a lighter, more
expensive crude oil to minimize low value residual fuel oil production, or
running a heavier, less expensive crude oil and accepting this low valued
production. Some refineries are unable to process heavy sour crude oil under
any circumstances because of their location and/or design. The most
sophisticated refinery configuration--the heavy coking refinery--can take
advantage of lower priced, heavy sour crude oil while producing relatively
little residual fuel oil and yielding a higher valued mix of products.
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<PAGE>
Heavy/Light Differential
The economics of crude oil selection compares the discounts offered for lower
quality crude oil to the gain on making higher value products instead of
residual fuel. The refining margin of a heavy coking refinery is highly
sensitive to the dollar per barrel price difference between heavy sour crude
oil, such as Maya, and light sweet crude oil, such as West Texas Intermediate.
This difference is often referred to as the "heavy/light differential." This
measurement provides a reliable indication of the profitability advantage of a
heavy coking refinery because a wider heavy/light differential typically
results in lower cost feedstocks and a higher resulting refinery margin.
According to Purvin & Gertz, from January 1988 through March 1999 the six month
moving average of the heavy/light differential ranged from a high of $8.90 to a
low of $3.76 with an average of $5.83 as shown in the following chart.
[Chart]
According to Purvin & Gertz, in the late 1980s, conversion capacity was fully
utilized with little or no excess capacity. As a result, returns on investment
for refiners motivated new investments in conversion capacity. By the early
1990s, the rate of addition of conversion capacity considerably exceeded the
needed level. Many producers added this capacity with the intention of
processing heavy sour crude into low sulfur diesel and reformulated gasoline.
Many refiners found that the most economic way of accomplishing this was to
combine various refinery modifications made in response to regulatory changes
with expansions of conversion capacity. Since conversion capacity is generally
the most profitable component of a refinery, many refiners believed that
increasing it was the most effective way to maximize returns on product quality
improvement investments. However, because so many refiners recognized the
potential benefit of increasing conversion capacity, an overbuilding of
capacity resulted. The overabundance of conversion capacity drove up demand for
heavy feedstock and resulted in a narrowing of the heavy/light differential
through 1995.
Recovery in the heavy/light differential occurred in 1996 and 1997. Purvin &
Gertz believes that while this recovery was due in part to temporary refinery
operating problems at several major refinery units, which decreased the
availability of conversion capacity, this recovery was primarily driven by the
rising output of heavy sour crude oil in the Western Hemisphere. This
increasing production of heavy sour crude oil resulted in severe price
competition and residual fuel oil oversupply. The differentials reached a peak
late in 1997 and early 1998 due to these factors. In April 1998, the trends
began to reverse and the heavy/light differential began to narrow. This
reversal was brought about by the confluence of a number of factors. These
include the effects of the Asian financial crisis, which reduced demand for
refined products and opened up capacity worldwide. In addition, low oil prices
and high natural gas prices in the United States caused demand for residual
fuel to increase rather dramatically. At the same time, export demand for
residual fuel increased sharply due to El Nino related hydropower shortages in
Mexico.
Although the rate of increase in conversion capacity fell sharply after 1994,
according to Purvin & Gertz several major projects are currently underway. In
addition, several conversion projects are linked to supplies of
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<PAGE>
heavy sour crude oil from Venezuela and Mexico. Purvin & Gertz expects these
conversion projects to absorb increases in heavy sour crude oil production. Net
additions in recent years have been at a rate of 2% per year in the United
States and nearly 4% worldwide.
According to Purvin & Gertz, the recent heavy sour crude oil production cuts
by Venezuela and Canada caused the heavy/light differential to narrow. At the
same time, new conversion capacity was being brought on and was absorbing any
excess heavy feedstock, thereby strengthening heavy feedstock prices and
further narrowing the differential. In addition, high natural gas prices
coupled with low residual fuel oil prices are encouraging the burning of
residual fuel, thereby squeezing the heavy feedstock balance and narrowing the
heavy/light differential even further. Even so, the differential averaged about
$5.00 over the first six months of 1999.
Purvin & Gertz believes domestic supply constraints in 1998 increased the
price of West Texas Intermediate above the level which would otherwise be
expected given the global supply-demand balance. Purvin & Gertz believes these
constraints are in the process of being reversed and expects them to reduce the
price of West Texas Intermediate. Because these supply constraints did not have
a significant impact on the Gulf Coast price of Maya, Purvin & Gertz expects
the heavy/light differential to contract as West Texas Intermediate prices
decline relative to Maya.
Purvin & Gertz believes that low demand for petroleum caused by the
continuation of the Asian financial crisis will cause Venezuela and other OPEC
producers to constrain production through 2000. Purvin & Gertz expects that
production through 2000 will be further constrained under the terms of the
March 1999 OPEC agreement. Mexico has agreed to constrain exports as well.
According to Purvin & Gertz, these factors will tend to keep the heavy/light
differential around $5.00 through 2000.
Purvin & Gertz expects that after the year 2000, the heavy/light differential
will begin to widen again since they expect all of the key factors determining
the heavy/light differential to turn favorable:
. as world economy, particularly Asia, improves, demand will grow rapidly;
. crude oil prices increase as demand increases;
. crude oil production increases, particularly heavy sour crude oil, as
demand for OPEC crude oil increases since OPEC crude oil is generally
heavier;
. Venezuela, Mexico and Canada will expedite heavy oil production; and
. light product demand and supply of heavy sour crude oil will likely
increase faster than new conversion capacity can be added.
Additional discussion of these conclusions are included in Purvin & Gertz's
Crude Oil and Refined Product Market Forecast provided to you as Annex C.
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EXISTING PORT ARTHUR REFINERY
AND THE REFINERY UPGRADE PROJECT
Existing Port Arthur Refinery
The Port Arthur refinery is located in Port Arthur, Texas and is situated on
an approximately 4,000 acre site, of which less than 100 acres are occupied by
active operating units. The Port Arthur refinery has a current rated crude oil
throughput capacity of approximately 232,000 barrels per stream day and the
ability to process 100% sour crude oil, including up to 20% heavy sour crude
oil, and has coking capabilities. The Port Arthur refinery has the ability to
produce jet fuel, 100% low-sulfur diesel fuel, 55% summer reformulated gasoline
and 75% winter reformulated gasoline. The Port Arthur refinery's Texas Gulf
Coast location provides access to numerous cost effective domestic and
international crude oil sources, and its products can be sold in central and
eastern United States as well as in export markets.
In February 1995, Clark Refining & Marketing purchased the Port Arthur
refinery together with related terminals, pipelines and other assets from
Chevron U.S.A. Products and some affiliated entities. Clark Refining &
Marketing also acquired legal title to Chevron's chemicals facility and lube
oil distribution facility, which are integrated with the Port Arthur refinery.
The chemicals facility and the lube oil distribution facility are being leased
to, and operated by, Chevron under long term leases providing for a nominal
rent and containing a purchase option in favor of Chevron at a nominal purchase
price. Clark Refining & Marketing also entered into agreements with Chevron and
its affiliates providing for, among other things, various services and the sale
and purchase of various refined products.
Refinery Upgrade Project
The purpose of the refinery upgrade project is to increase the ability of the
Port Arthur refinery to process heavy sour crude oil. The business strategy of
Clark Refining Holdings in undertaking the refinery upgrade project is to earn
a higher margin on processing operations at the Port Arthur refinery and take
advantage of our long term crude oil supply agreement with P.M.I. Comercio
Internacional.
The refinery upgrade project consists primarily of the construction of a new
delayed coking unit, the installation of a new vacuum gas oil hydrocracking
unit, the installation of a new sulfur complex and an expansion of the existing
crude unit. Also included in the scope of the refinery upgrade project are
various improvements to the infrastructure of the existing Port Arthur refinery
and various modifications of existing processing units at the Port Arthur
refinery. The Port Arthur refinery has several important characteristics that
make it attractive for this type of investment, including its Gulf Coast
location which provides excellent access to waterborne deliveries of Mexican
crude oil and the fact that the Port Arthur refinery currently has much of the
infrastructure and processing capability necessary to support an upgraded
operation, which we believe lowers the capital cost.
The following table highlights the impact we expect the refinery upgrade
project to have on the Port Arthur refinery as a whole. The figures used under
the heading "after" correspond to the data used by Purvin & Gertz in the base
case financial model which is part of their report included in this prospectus
as Annex B and represents the combined operations of Clark Refining & Marketing
and Port Arthur Coker Company.
<TABLE>
<CAPTION>
The Port Arthur
Refinery
-----------------------
Before After
Upgrade Upgrade
----------- -----------
<S> <C> <C>
Crude Oil Throughput
Capacity (barrels per
stream day)............ 232,000 250,000
Coker Throughput
Capacity (barrels per
stream day)............ 38,000 80,000
API Gravity............. 34(degrees) 24(degrees)
Sulfur Processing
Capacity............... 1.6% 3.1%
Solomon Complexity
Rating................. 12.2 15.9
Production (barrels per
calendar day).......... 221,700 254,700
</TABLE>
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<PAGE>
Throughput capacity is a term used to measure the capacity of a refinery or a
particular processing unit at a refinery to process crude oil or another
feedstock. API gravity is a method of differentiating crude oil quality which
is closely correlated to product yields. In other words, the processing of a
crude oil with a higher API gravity should result in increased product yields
when compared to the processing of a crude oil with a lower API gravity.
Solomon complexity rating is oil industry standard for comparing refineries
based on the complexity of their configurations. A more "complex" refinery such
as one with conversion capacity generally produces a more valuable mix of
products.
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COKER GROSS MARGIN SUPPORT MECHANISM IN
OUR LONG TERM CRUDE OIL SUPPLY AGREEMENT
The primary function of our coker project will be to allow the economical
refining of Maya heavy sour crude oil into higher valued light intermediate
products. These light products upon further processing and blending, are
capable of being sold as home heating oil, on and off road diesel fuel or no. 2
fuel oil, gasoline and other similar products, which have historically been the
highest value products derived from crude oil. Maya crude oil has historically
been priced less than lighter, sweeter crude oil due its higher content of
impurities and sulfur that make it more difficult to process, and without the
proper processing equipment, result in a higher percent of historically low
value residual products, such as no. 6 fuel oil, asphalt and other similar
products. As such, the profitability of constructing coker equipment and our
coker project is based on the price difference between residual products, as
represented by no. 6 fuel oil in the coker gross margin support formula
described below, and the ultimate products to which these residual products can
be converted in the coking process, as represented by gasoline and no. 2 fuel
oil below. If this spread between residual products and light products were
very narrow for an extended period of time, the profitability of a coker
project would be less and the risk to noteholders or a coker owner and operator
would be greater.
In negotiating our long term oil supply agreement with P.M.I. Comercio
Internacional, we attempted to mitigate this risk substantially through the use
of a coker gross margin support mechanism. This mechanism is composed of a
formula that was designed to be a proxy for the economic opportunity of
constructing coking equipment, which is compared to a negotiated differential
guarantee amount of $15 per barrel. This mechanism is designed to moderate our
coker gross margin fluctuations. The mechanism contains a formula that is
intended to be an approximation for coker gross margin and is designed to
provide for a minimum average coker gross margin during the first eight years
following completion of the refinery upgrade project assuming we achieve
completion by July 2001, and thus will not apply for the entire duration of the
notes. The price we pay for Maya will be the regular price adjusted for a
monthly adjustment amount based on the difference between the differential
formula amount and a $15 per barrel differential guarantee amount. The
differential formula amount is calculated as follows:
Differential formula amount = (0.5 X RUL) + #2FO-(1.5 X #6FO)
Where:
RUL = average of U.S. Gulf Coast market prices for conventional 87
octane unleaded gasoline
#2FO = average of U.S. Gulf Coast market prices for 0.2% sulfur no. 2
fuel oil
#6FO = average of U.S. Gulf Coast market prices for 3% sulfur no. 6
fuel oil
The gasoline and no. 2 fuel oil prices were selected as proxies for the
prices that we can reasonably expect to receive for the light refined products
produced by our coking unit. The no. 6 fuel oil price was selected as a proxy
for coker feedstock prices because of its high degree of historical correlation
with Maya prices. Our long term crude oil supply agreement also has a provision
that is designed to compensate for changes in this historical correlation.
We use the differential formula amount above to calculate the monthly
adjustment amount as follows:
Monthly adjustment amount = (differential formula amount-$15) X 36.6% X
Our Maya delivered
during the month.
This amount is referred to in our long term crude oil supply agreement as a
monthly surplus or shortfall, depending on whether it is a positive or negative
number. This 36.6% factor is used because we expect that every 100 barrels of
Maya processed through our crude unit will yield approximately 36.6 barrels of
coker feedstock.
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At the end of each calendar quarter, all monthly adjustment amounts, whether
positive or negative, are netted under a mechanism set forth in our long term
crude oil supply agreement, resulting in a price adjustment applicable to Maya
to be purchased in the succeeding calendar quarter. The discount applied to the
price of Maya in any quarter may not exceed $30 million. The premium applied to
the price of Maya in any quarter may not exceed the lesser of $20 million or
the net aggregate amount of shortfalls for the prior period. The net adjustment
amount, whether positive or negative, existing at the end of the period during
which the coker gross margin support is available will be applied over the
remaining term of the agreement, after giving effect to the operation of the
differential mechanism in the last period. The discount we receive in any
quarter will not exceed $30 million and the premium we pay in any quarter will
not exceed $20 million.
If the differential formula amount is calculated over the period 1987-1998
and regressed against the historical heavy/light differentials, the
mathematical result implies that the $15 per barrel differential guarantee
amount would correspond to a heavy/light differential of $5.94 per barrel. This
is $0.24 per barrel above the historical average heavy/light differential of
$5.70 per barrel over the same period. Therefore the coker gross margin support
mechanism in our long term crude oil supply agreement would have added to our
coker gross margin during that period.
According to Purvin & Gertz, the price adjustment mechanism in our long term
crude oil supply agreement serves as a suitable method of stabilizing coker
gross margin fluctuations.
Below is a sample quarterly calculation of the operation of the price
adjustment mechanism contained in our long term crude oil supply agreement,
based on the year 2001 price forecast by Purvin & Gertz and assuming quarterly
Maya volume of 13.8 million barrels:
<TABLE>
<S> <C>
Differential Formula Amount = (0.5 x $19.48) + $18.40 - (1.5 x
$10.22) = $12.81
Differential Guarantee Amount -$15.00
-------
Shortfall per barrel $ 2.19
Quarterly Maya Volume (millions of barrels) 13.8
Coker Feedstock Factor x 0.366
-------
Eligible Volume (millions of barrels) 5.1
Coker Gross Margin Shortfall per barrel of feedstock x$ 2.19
-------
Discount due (millions of dollars) $ 11.0
Quarterly Maya Purchase Cost without discount $10.88
Quarterly Maya Purchase Cost after application of discount $10.08
</TABLE>
See "Description of Our Principal Project Documents--Long Term Crude Oil
Supply Agreement" for a more complete and detailed discussion of our crude oil
supply arrangement. You should also read "RiskFactors--Market Risks" regarding
the risk that the coker gross margin support mechanism may not adequately
protect against all fluctuations in the relative prices of heavy sour crude oil
and refined products. See Tables V-12, V-14, V-16, V-17, V-19, V-21, V-23, V-
25, V-26, V-27 and V-28 in Annex B to this prospectus for other projection
cases produced by Purvin & Gertz that include alternative calculations of the
coker gross margin adjustment mechanism.
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<PAGE>
OUR COKER PROJECT
Our coker project will use delayed coking technology to enable the Port
Arthur refinery to process increased volumes of heavy sour crude oil. We expect
the total cost of constructing our new units described below and completing the
additional improvements that comprise our coker project to be $715 million,
including an allowance for estimated price escalation and contingencies.
Our Portion of the Refinery Upgrade Project
Delayed Coker. Our new 80,000 barrel per stream day delayed coking unit will
be equipped with six coke drums. This unit converts vacuum tower bottoms from
the refinery's crude unit through thermal cracking process into lighter, more
valuable products, principally heavy gas oil that is fed to the hydrocracker,
light gas oil that is blended into distillate after further processing, naphtha
feed for further processing, butane/butylene, propane/propylene and fuel gas.
Petroleum coke is a byproduct of this process and is sold principally for
utility fuel.
According to Purvin & Gertz, delayed coking technology has been utilized for
well over 50 years and is one of the most widely used processes to upgrade low
value heavy residue into higher value light products. Our delayed coking unit
will use a well established and commercially proven Foster Wheeler USA design.
According to Purvin & Gertz, this design has the benefit of the prior
experience of Foster Wheeler USA, which has designed five coker units with a
capacity of 75,000 barrels per day or greater, and it should result in more
favorable product yields and lower operating costs.
Vacuum Gas Oil Hydrocracker. Our new vacuum gas oil hydrocracker is designed
to process 35,000 barrels per day of feedstock consisting of heavy gas oil from
our coking unit and virgin vacuum gas oil and light cycle oil from other
refinery processing units. Our hydrocracker is designed for the conversion of
the heavy feedstock into at least 50% light products. According to Purvin &
Gertz, full hydrocracker conversion of the vacuum gas oil is not required since
Clark Refining & Marketing's existing fluid catalytic conversion unit has the
capacity to convert the remaining vacuum gas oil. This allows our hydrocracker
to have a smaller second stage reactor than is typical for vacuum gas oil
hydrocrackers, which reduces our capital costs.
We will license our hydrocracker design from Chevron Research and Technology
Company which is also providing a process guarantee for our hydrocracker.
According to Purvin & Gertz, vacuum gas oil hydrocracking is a well established
and commercially proven technology, and the expected yields from our new
hydrocracker can be achieved.
Sulfur Recovery Units. Our new sulfur complex will operate in parallel with
existing sulfur recovery units at the Port Arthur refinery to process the
incremental hydrogen sulfide that will result from the processing of increased
quantities of heavy sour crude oil at the Port Arthur refinery. Our sulfur
complex will consist of:
. a new dual train sulfur recovery unit with a total capacity of 417 long
tons per stream day,
. a new tailgas cleanup unit that uses licensed technology from Shell Oil
Company called Shell Claus Offgas Treater or "SCOT",
. a new sour water stripper and
. a new amine treating unit.
According to Purvin & Gertz, the technology selected for our new sulfur
recovery complex will result in a well-designed unit with adequate sulfur
removal capacity to support the expected requirements of the Port Arthur
refinery.
Infrastructure Improvements. Our coker project will also include the
following additional infrastructure improvements at the refinery:
. interconnecting of process units and utility piping between our units;
. converting existing tanks into coker feed tanks;
. constructing a new dedicated flare for our units;
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<PAGE>
. constructing a new substation to supply power to our new units;
. constructing a new control unit for our units; and
. installing truck and rail loading facilities for sulfur.
Clark Refining & Marketing's Portion of the Refinery Upgrade Project
In addition to the new processing units described above which comprise our
coker project, we are leasing existing processing units from Clark Refining &
Marketing. In connection with this lease, Clark Refining & Marketing is
obligated to make modifications and infrastructure improvements during 1999 and
2000 to integrate these existing processing units with our coker project at an
estimated cost of up to $120 million. In return, we are obligated to make
rental payments to Clark Refining & Marketing for our use of these modified
units. As of December 31, 1999, Clark Refining & Marketing had expended
approximately $51 million towards this commitment. According to Purvin & Gertz,
these modifications to be undertaken by Clark Refining & Marketing are a group
of routine, small refinery projects normally carried out during turnarounds and
do not present a major risk to the successful start-up, operation or
integration of our coker project.
Modification of Crude Unit. The existing crude/vacuum unit, which is
presently designed to process 232,000 barrels per stream day of light to medium
sour crude oil, will be modified to process 250,000 barrels per stream day.
These modifications include changes to the process exchangers to provide more
preheat to the crude unit, upgrading the vacuum unit heater and miscellaneous
pumps and piping. These activities will be completed prior to start-up of our
new units. The crude unit revamp design is adequate to support the processing
of the expected increased volume of heavy sour crude oil.
Modification of Hydrotreaters. The existing distillate and kerosene
hydrotreating units at the Port Arthur refinery are being revamped to increase
capacity for handling the higher sulfur distillate products that will be
produced by the increased volume of heavy sour crude oil. These modifications
involve increasing the size of reactors and catalyst volume through replacement
of reactors. In fact, replacement of reactors in one of the hydrotreaters has
already been completed. These modifications will be completed three to six
months prior to start-up of our coker project.
Infrastructure Improvements. Clark Refining & Marketing will also undertake
the following additional infrastructure improvements at the refinery:
. interconnecting of process units and utility piping between our and their
units;
. upgrading existing crude handling facilities, including a new crude oil
pumping station;
. expanding the firewater loop;
. upgrading the electrical system; and
. modifying coke handling facilities.
The New Hydrogen Plant
To provide the hydrogen necessary to the refinery upgrade project, Air
Products has agreed to construct a new 100 million standard cubic feet per
stream day hydrogen supply plant at the Port Arthur refinery on land leased
from Clark Refining & Marketing. This new hydrogen supply plant is intended to
enable Air Products to meet its obligations under its hydrogen supply agreement
with us. The Air Products hydrogen supply plant is also intended to supply
hydrogen, steam and electricity to Clark Refining & Marketing for use at the
Port Arthur refinery.
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<PAGE>
Air Products is obligated to us to ensure that the hydrogen supply plant is
ready to operate no later than December 2000, the date when we expect our heavy
oil processing facility to first need hydrogen. Purvin & Gertz believes that
this is achievable and that it is likely that the hydrogen supply plant will be
constructed and ready for start-up before our coker project. For a description
of the hydrogen supply agreement, please see "Description of Our Principal
Project Documents--Hydrogen Supply Agreement."
The hydrogen supply plant is being built principally to provide us and Clark
Refining & Marketing with our required supply of hydrogen. The estimated total
cost of constructing the hydrogen supply plant is $125 million and is being
funded by Air Products. We will have no rights, ownership or otherwise,
relating to the hydrogen supply plant.
Process Flow at the Port Arthur Refinery
The following diagram illustrates the major components of the refinery
upgrade project, showing (1) our new processing units, referred to in this
prospectus as the coker project, (2) the processing units we are leasing from
Clark Refining & Marketing and which Clark Refining & Marketing is upgrading
and (3) the new hydrogen supply plant that Air Products is constructing and
will own at the Port Arthur refinery.
[Process Flow Chart]
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<PAGE>
Construction of the Refinery Upgrade Project
The refinery upgrade project was formally initiated in April 1998, and Clark
Refining & Marketing began construction in September 1998 pursuant to a
reimbursable construction contract with Foster Wheeler USA. We purchased the
work in progress under such contract related to our coker project in part with
funds from the sale of the outstanding notes and have entered into our
construction contract with Foster Wheeler USA to complete our coker project.
For a more detailed summary of this contract, see "Description of Our Principal
Project Documents--Construction Contract."
Pursuant to our services and supply agreement, Clark Refining & Marketing is
managing and supervising the construction of our new units and other equipment
and overseeing the performance of Foster Wheeler USA under our construction
contract. In addition, Clark Refining & Marketing is performing all our
obligations, other than payment obligations, under our construction contract
with Foster Wheeler USA, including all project management and construction
management functions, quality surveillance, performance of start-up activities,
provision of needed water and utilities and provision of all necessary
feedstreams for operation of our coker project during start-up and performance
testing. For a more detailed summary of the services and supply agreement, see
"Description of Our Principal Project Documents-- Services and Supply
Agreement."
Pursuant to our facility and site lease with Clark Refining & Marketing, if
Clark Refining & Marketing does not complete the upgrades to existing refinery
processing units which we are leasing from them by October 2000, we have the
right to complete these modifications at Clark Refining & Marketing's expense
so that the overall completion of the refinery upgrade project is not delayed.
Clark Refining & Marketing has entered into a reimbursable construction
contract with Foster Wheeler USA for performance of the majority of these
modifications and Clark Refining & Marketing's portion of the other refinery
improvements. These modifications and improvements will be paid for by Clark
Refining & Marketing. Clark Refining & Marketing arranged for its lenders to
provide a standby letter of credit for $97 million to Foster Wheeler USA to
ensure that funds are available for payments to Foster Wheeler USA under its
reimbursable construction contract. Foster Wheeler USA has also agreed not to
draw on the letter of credit for amounts due to it unless Purvin & Gertz, in
its role as independent engineer, has certified that the work related to the
requested drawing has been performed and the amounts requested are due and
payable. As of February 29, 2000, the letter of credit had been reduced to $79
million based on payments made to Foster Wheeler USA. For a more detailed
summary of the facility and site lease and the reimbursable construction
contract, see the applicable sections under "Description of Our Principal
Project Documents."
The chart below outlines our anticipated time schedule for the refinery
upgrade project:
<TABLE>
<CAPTION>
Event Target Date Start Damages Guaranteed Date
----- -------------- ------------- ---------------
<S> <C> <C> <C>
Coker Project
Project announcement.............. April 1998
Construction start................ September 1998
Financial close................... August 1999
Mechanical completion............. November 2000 January 2001 March 2001
Substantial reliability........... January 2001 January 2001 September 2001
Final completion.................. March 2001 December 2001
Clark Portion of the Refinery
Upgrade Project.................. October 2000
Air Products Project.............. October 2000 December 2000 December 2000
</TABLE>
Operation of our Heavy Oil Processing Facility
Pursuant to our services and supply agreement with Clark Refining &
Marketing, Clark Refining & Marketing will provide to us a number of services
and supplies needed for operation of our heavy oil processing facility. Clark
Refining & Marketing is required to provide all such services and supplies in
accordance with specified standards, including prudent industry practices.
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<PAGE>
Operation and Management
Port Arthur Coker Company employees will operate the processing units
comprising our coker project. Clark Refining & Marketing will supervise and
train our employees, operate the remaining units comprising our heavy oil
processing facility and be responsible for the management of our heavy oil
processing facility. In addition, Clark Refining & Marketing is responsible for
managing our crude oil purchases and the transportation of such oil to the Port
Arthur refinery. Clark Refining & Marketing is also obligated to procure and
manage supply contracts on our behalf for the portion of light crude oil that
is necessary for processing heavy crude oil at the refinery and for an
alternative supply of crude oil should Maya no longer be available to us
pursuant to our long term crude oil supply agreement with P.M.I. Comercio
Internacional.
Maintenance
Heavy Oil Processing Facility. Clark Refining & Marketing is responsible for
routine, preventative and major maintenance for all portions of our heavy oil
processing facility. Our heavy oil processing facility is designed for
continuous operation, and maintenance work will be performed on a regular basis
by Clark Refining & Marketing. In this regard, Clark Refining & Marketing
intends to use monitoring and preventative maintenance measures to ensure
reliable operations with minimal failures and unexpected shutdowns. Maintenance
of our heavy oil processing facility will require periodic shutdown of various
processing units. In particular, the coker, hydrocracker and sulfur complex
will require three-week shutdowns for maintenance every four years. Every six
months we will set aside a portion of our revenues, to the extent available, to
pay for turnaround expenses expected to be incurred during our next scheduled
maintenance turnaround of the new processing units.
Port Arthur Refinery. Clark Refining & Marketing is also obligated under our
services and supply agreement to operate and maintain the other portions of the
Port Arthur refinery owned by it in a manner that ensures its ongoing ability
to perform its obligations to us and that is consistent with specified
standards and the efficient operation of our heavy oil processing facility. To
remain competitive with other refiners and to preserve operating conditions at
the Port Arthur refinery, Clark Refining & Marketing has invested significant
amounts in the maintenance of the major processing units at the refinery. Clark
Refining & Marketing generally has conducted maintenance turnarounds in
accordance with the refinery's normal maintenance cycles in an effort to
minimize disruptions to the refinery's operations. Clark Refining & Marketing
is obligated to continue to coordinate the scheduling and performance of all
maintenance turnarounds of processing units at the Port Arthur refinery,
including turnarounds of units comprising our heavy oil processing facility, in
accordance with industry standards and in a manner that, when possible,
minimizes operational disruptions to, and economic impact on, when possible,
both Clark Refining & Marketing and us.
Infrastructure and Utilities
We share common utilities and infrastructure with Clark Refining & Marketing
at the Port Arthur refinery. As part of the services provided by Clark Refining
& Marketing pursuant to our services and supply agreement, Clark Refining &
Marketing provides us with utilities and other support services using, among
others, the following refinery facilities:
. the electrical distribution system;
. the steam distribution system;
. the natural and fuel gas distribution system;
. the nitrogen distribution system;
. the waste management and wastewater treating facilities;
. the analytical laboratory;
. crude oil storage facilities;
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<PAGE>
. the refinery pipeline system;
. water and air distribution facilities; and
. warehouse storage.
Other Services and Supplies
Clark Refining & Marketing will also provide us with all feedstocks (other
than crude oil), catalysts, chemicals and other materials necessary for the
operation of our heavy oil processing facility and a number of other services,
including contract management services, procurement services, personnel
management services, security services and emergency response services.
Processing Arrangements
Under our services and supply agreement, Clark Refining & Marketing also has
a right of first refusal to require us to process crude oil for them in an
amount equal to the portion, if any, of the processing capacity of our heavy
oil processing facility that exceeds the amount we need to process the Maya
available to us under our long term crude oil supply agreement with P.M.I.
Comercio Internacional or an equivalent amount available to us under an
alternative supply arrangement. Clark Refining & Marketing will pay us a
processing fee for any of its crude oil and other feedstocks that we process
under this right of first refusal. We expect this portion to be approximately
20% of the processing capacity of our heavy oil processing facility.
Sale of Our Products
Pursuant to our product purchase agreement with Clark Refining & Marketing,
Clark Refining & Marketing is unconditionally obligated to accept and pay for
all final and intermediate products of our heavy oil processing facility that
we tender for delivery.
Clark Refining & Marketing, as our sole customer, has the right to request
that the heavy oil processing facility produce a certain mix of products. This
right, however, is subject to specified limitations that are designed to
ensure:
. that we utilize the entire amount of Maya available to us under our long
term crude oil supply agreement or an equivalent amount from an
alternative supplier,
. that we are able to service the notes and our other debt obligations on
an ongoing basis and
. that the operations of the Port Arthur refinery are optimized in a manner
that is mutually beneficial to us and Clark Refining & Marketing and that
does not benefit Clark Refining & Marketing at our expense.
Our Competition and Marketing Environment
We have not entered into any other arrangements for the sale of our refined
products. Thus, our product purchase agreement is our sole source of revenue
from the sale of refined products. According to Purvin & Gertz, however, we
are located in the most liquid refined products market in the world and if
Clark Refining & Marketing no longer meets its purchase obligations to us, our
intermediate and final refined products would be readily marketable to third
parties at somewhat discounted prices. For a more detailed discussion of these
conclusions you should read the sections captioned "Conclusions--Stand-Alone
Case" and "Economic Model--Stand-Alone Case" in Annex B to this prospectus.
We have no crude oil reserves and are not engaged in exploration and
production activities. We will obtain our crude oil requirements pursuant to
our long term crude oil supply agreement with P.M.I. Comercio Internacional,
on the spot market from unaffiliated sources or from Clark Refining &
Marketing pursuant to our 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.
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Our feedstocks and refined products are principally commodities and the
pricing of such feedstocks and refined products under our services and supply
agreement and product purchase agreement is intended to reflect market prices.
As a result, our operating cash flows and earnings will be 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,
the rate of industry investments, the availability of imports, the marketing of
competitive fuels and the extent of government regulations. Also relevant are
seasonal fluctuations with generally stronger operating cash flows and earnings
expected during the higher transportation-demand periods of the spring and
summer and weaker operating cash flows and earnings expected during the fall
and winter.
We also expect our operating cash flows and earnings to be affected by the
competitive position of the Port Arthur refinery. The refining segment of the
oil industry is highly competitive. Many of the Port Arthur refinery's
principal competitors are owned by integrated multinational oil companies that
are substantially larger than Clark Refining & Marketing. Because of their
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 shortages.
The Port Arthur refinery's principal competitors are 28 other refineries
located on the U.S. Gulf Coast. In Purvin & Gertz's opinion, the refinery
upgrade project will transform the Port Arthur refinery into one of the top
five refineries in this Gulf Coast market in terms of competitiveness and heavy
crude oil conversion capacity.
Environmental Matters
General
Our operations are subject to extensive federal, state and local
environmental, health and safety laws and regulations, including those
governing discharges to the air and water, the handling and disposal of solid
and hazardous wastes, and the remediation of contamination. The failure to
comply with such laws and regulations can lead to, among other things, civil
and criminal penalties and in some circumstances the temporary or permanent
curtailment or shutdown of operations. The nature of the refining business
exposes us to risks of liability due to the production, processing, storage and
disposal of materials that can cause contamination or personal injury if
released into the environment. Pursuant to our services and supply agreement,
Clark Refining & Marketing has committed to take actions necessary to cause us
to comply with these laws and regulations.
We expect that the nature of the refining business will make us subject to
increasingly stringent environmental and other laws and regulations that may
increase the costs of operating our heavy oil processing facility above
currently projected levels. We may be required to make future expenditures to
comply with more stringent standards for air emissions, wastewater discharge
and the remediation of contamination. As our coker project is integrated with
the operations of the Port Arthur refinery, any developments in environmental
laws that adversely impact Clark Refining & Marketing's operations could also
adversely affect our financial condition or results of operations. It is
difficult to predict the effect of future developments in these laws and
regulations on our financial condition or results of operations.
We are unaware of any environmental or health and safety liabilities and
expenses that are reasonably likely to have a material adverse effect on our
results of operations but cannot assure you that such liabilities and expenses
will not occur. You should read "Risk Factors--Environmental Risks for a
discussion of the risk that environmental concerns pose to our Coker Project."
Existing Conditions
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
52
<PAGE>
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. The Port Arthur refinery is located on a contaminated site.
Under the 1994 purchase agreement between Clark Refining & Marketing and
Chevron Products USA relating to the Port Arthur refinery, Chevron retained
environmental remediation obligations regarding pre-closing contamination at
over 97% of the refinery site. Clark Refining & Marketing assumed
responsibility for any remediation that is required in and under the remaining
approximately 3% of the refinery site, which consists of specified areas that
extend 25 to 100 feet from active operating units, including soil and ground
water and, encompasses less than 50 acres of the total Port Arthur refinery
site surface area. Clark Refining & Marketing has estimated its liability for
remediation of groundwater and soil in these areas at $27 million. Chevron is
obligated to remediate the contamination in the areas for which it has retained
responsibility as and when required by law, in accordance with remediation
plans negotiated by Chevron and the applicable federal or state agencies.
We evaluated the cost associated with remediation of the groundwater and soil
of the land that we are leasing within the boundaries of the Port Arthur
refinery and estimate remedial costs relating to our coker project site at $1.6
million. Clark Refining & Marketing has agreed to retain liability regarding
contamination existing at the coker project site and has indemnified us against
such liabilities. However, if Clark Refining & Marketing breaches its
remediation obligations, we could incur substantial additional costs in
remediating the contamination, which could impair our ability to make payments
on the notes and our other debt when due.
We believe that the remediation costs relating to contamination at our coker
project site would be deferred until the final decommissioning of our coker
project. However, actual remediation costs, as well as the timing of such
costs, are dependent on a number of factors over which neither we nor Clark
Refining & Marketing has control, including changes in applicable laws and
regulations, priorities of regulatory officials, interest from local citizens
groups and development of new remediation methods.
Permits, Applications and Status
In August 1998, Clark Refining & Marketing amended its flexible air emissions
permit from the Texas Natural Resource Conservation Commission to allow Clark
Refining & Marketing to undertake the refinery upgrade project. At our and
Clark Refining & Marketing's request, the Texas Natural Resource Conservation
Commission amended Clark Refining & Marketing's flexible air emissions permit
and issued to us a new air emissions permit in May 1999. As a result, we now
hold an air emissions permit from the Texas Natural Resource Conservation
Commission which covers construction and operation of our new processing units.
Clark Refining & Marketing holds an amended flexible air permit from the Texas
Natural Resource Conservation Commission which covers other processing units
and facilities at the Port Arthur refinery including the processing units that
we are leasing from Clark Refining & Marketing and their other facilities which
we have a right to use. Under applicable environmental regulations, we have the
right to operate such equipment and facilities pursuant to Clark Refining &
Marketing's existing permits. We also have a standby air emissions permit,
which contains a provision permitting such permit to be activated by us to
cover the entire Port Arthur refinery, including such equipment and facilities,
upon notice to the Texas Natural Resource Conservation Commission. Under our
supply and services agreement with Clark Refining & Marketing, we have agreed
not to exercise our rights to activate this permit unless the permit is
required to allow us to continue our operation of our units.
Proposed Gasoline Sulfur Specifications
On May 13, 1999, the United States Environmental Protection Agency published
a proposed rule that would require on a nationwide basis a substantial
reduction in the sulfur content of gasoline. A final rule establishing the new
gasoline sulfur specifications was finalized in December 1999. However,
according to Purvin & Gertz, with our new hydrocracker and the existing vacuum
gas oil hydrotreater, the Port Arthur refinery will likely only require
additional hydrotreating on some gasoline blendstock streams to allow for the
production of gasoline meeting the new specifications. We and Purvin & Gertz
expect this capital expenditure
53
<PAGE>
to be substantially less than $50 million through the use of idle equipment
currently located at the Port Arthur refinery.
MTBE
Recent concerns regarding groundwater contamination by methyl tertiary butyl
ether, also known as "MTBE," a gasoline additive, have prompted a panel of the
Environmental Protection Agency to recommend that the U.S. Congress enact a ban
on MTBE usage in gasoline. Similarly, the governor of California recently
signed an executive order regarding a ban on MTBE usage in gasoline in the next
few years. If a ban on MTBE usage were to spread throughout the United States,
we would be prohibited from utilizing MTBE in gasoline blends. However, we do
not plan to produce MTBE and Purvin & Gertz has concluded that a ban on MTBE
usage would not have a material effect on our operations and cash flow or the
competitiveness of the Port Arthur refinery.
Insurance
Pursuant to our financing documents, Port Arthur Coker Company is required to
maintain a specified minimum level of insurance in connection with our coker
project. In this regard, we are required to keep all our property of an
insurable character insured with such coverage and in such forms and amounts as
are customarily provided for facilities similar in size and type to our coker
project. Such insurance includes insurance against sudden and accidental
environmental damage, delay in start-up insurance and business interruption and
contingent business interruption insurance. For more description of the
insurance we are required to maintain, see "Description of Our Principal
Financing Documents--Common Security Agreement--Insurance."
Legal Proceedings
None of Port Arthur Coker Company, Port Arthur Finance, Sabine River nor
Neches River is currently a party to any pending legal proceedings, nor do we
have actual knowledge of any threatened legal proceeding.
Property
Port Arthur Coker Company, Port Arthur Finance and Sabine River lease office
space from Clark Refining & Marketing at 1801 S. Gulfway Drive, Office No. 36,
Port Arthur, Texas 77640, where we have our principal executive offices.
Our coker project will be located on a subdivided site totaling less than 50
acres within the Port Arthur refinery. Port Arthur Coker Company has entered
into a long term fully-prepaid ground lease with Clark Refining & Marketing for
such site. Pursuant to such ground lease, Clark Refining & Marketing has also
granted us an easement over the remainder of the Port Arthur refinery which is
owned by Clark Refining & Marketing and the right to use other specified
facilities and equipment at the refinery.
Port Arthur Coker Company is also leasing Clark Refining & Marketing'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 a
facility and site lease. Pursuant to this facility and site lease, Clark
Refining & Marketing has also granted us an easement across the remainder of
the Port Arthur refinery property owned by it, a portion of Clark Refining &
Marketing's dock adjacent to the Port Arthur refinery and specified pipelines
and crude oil handling facilities needed to transport crude oil from docking
facilities in Nederland, Texas, to the Port Arthur refinery. Both of these
leases have an initial term of 30 years which may be renewed at our option for
five additional renewal terms of five years each.
Employees
Port Arthur Coker Company expects to employ approximately 50 full-time
employees to operate our new units once our coker project is fully operational,
but currently only employs one individual who performs accounting services.
Port Arthur Finance, Sabine River and Neches River currently have no employees
and do not expect to have any employees.
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<PAGE>
INDEPENDENT ENGINEER'S REPORT SUMMARY
Selected conclusions of Purvin & Gertz's independent engineer's report are
summarized below. Purvin & Gertz's estimates for the coker project included in
this prospectus were not prepared with a view toward compliance with published
guidelines of the American Institute of Certified Public Accountants or
generally accepted accounting principles. Neither our independent auditors, nor
any other independent accountants, have compiled, examined or performed any
procedures with respect to our or Purvin & Gertz's estimates regarding our
coker project contained in this prospectus, nor have they expressed any opinion
or any form of assurance on such information or its achievability, and assume
no responsibility for, and disclaim any association with, the aforementioned
estimates. These figures represent Purvin & Gertz's best estimates of operating
and financial results of our coker project assuming the completion of our coker
project and expected mode of operation. You should read the entire report which
is set forth as Annex B to this prospectus.
In Purvin & Gertz's opinion, the refinery upgrade project will transform the
Port Arthur refinery into one of the top five refineries on the Gulf Coast in
terms of competitiveness and heavy crude oil conversion capacity. Based on
their review of the refinery upgrade project, they have reached the following
technical, commercial/marketing and financial conclusions:
Technical
. The design of the major new units to be installed at the Port Arthur
refinery, specifically our delayed coking and the hydrocracker units,
are based on licensed technology that is well-established and
commercially proven.
. The size and configuration of the new process units should integrate
well with the Port Arthur refinery.
. The refinery upgrade project capital cost estimate provided by Foster
Wheeler USA and Clark Refining & Marketing is reasonable and includes
all relevant items based on their review of the estimate.
. The contingency and escalation allowance included in the estimate is
adequate at this stage of the refinery upgrade project.
. The refinery upgrade project schedule of 31 months, from April 1998 to
mechanical completion in November 2000, is achievable.
. There are no apparent site conditions including known underground
obstructions or contamination that would lead to major cost overruns.
. The refinery upgrade project will have a useful life of at least 20
years extending well beyond the term of the debt financing.
. Foster Wheeler USA is a reputable engineering contractor experienced in
designing and constructing refining and petrochemical facilities. Foster
Wheeler USA is well qualified for the proposed assignment and has the
resources and financial strength necessary to fulfill their obligations
under our construction contract and their reimbursable construction
contract with Clark Refining & Marketing for their portion of the
refinery upgrade project.
. Our construction contract is favorable to us, is suitable for this type
of financing, and provides adequate protection to us for cost overruns,
completion risk, integration risk and inefficiencies.
. The required performance and reliability tests have been structured to
validate cash flow availability in order to support our anticipated debt
capacity and, if not, to cause Foster Wheeler USA to buydown our debt to
adjust it according to the reduced debt service capacity.
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<PAGE>
. The liquidated damages cap of $145 million represents up to $70 million
of delay damages and up to $75 million of buydown damages for
inefficiencies and is adequate for this type of project.
. The Clark Refining & Marketing portion of the refinery upgrade project,
including the crude oil unit and hydrotreater modifications and other
offsites and utilities to be undertaken by Foster Wheeler USA are a
group of relatively routine small refinery projects normally carried out
during turnarounds or during refinery operations, which Purvin & Gertz
expects will not present a major risk to the successful start-up,
operation and integration of our coker project.
. Clark Refining & Marketing is an experienced fuels refinery operator
currently processing Maya, operating two existing cokers at the Port
Arthur refinery and is well qualified to manage operations at the Port
Arthur refinery.
. Clark Refining & Marketing's crude oil import infrastructure and Sun
Pipe Line Company's Nederland terminal and connecting pipelines to the
Port Arthur refinery are adequate to support the volumes of imported
Maya and other crude oil contemplated for the refinery upgrade project's
operation. Several pipeline and terminal alternatives also exist to
deliver crude oil to the Port Arthur refinery if required.
. Air Products is a reliable hydrogen producer and the hydrogen supply
plant will be constructed in a timely manner and will produce the
required hydrogen and utilities. Approximately 50% of the required
hydrogen can be supplied by Air Products via pipeline as a backup, if
necessary.
Commercial and Marketing
. The long term crude oil supply agreement was designed to minimize the
effect of adverse refining cycles, and as a result, establish more
stable cash flow for us. In order to effect stable cash flows, our long
term crude oil supply agreement contains a formula that is intended to
be an approximation for coker gross margin and is designed to provide
for a minimum average coker gross margin over the first eight years
following completion of the refinery upgrade project. The mechanism
guarantees an average minimum $15.00 per barrel differential formula
related to coker gross margin via price adjustments on Maya.
. If the differential formula amount is calculated over the August 1987 to
December 1998 period and regressed against the historical West Texas
Intermediate/Maya differential, the mathematical results implies that
the $15 per barrel is equivalent to the West Texas Intermediate/Maya
differential of $5.94 per barrel. This is $0.24 per barrel above the
historical average West Texas Intermediate/Maya differential of $5.70
per barrel over the same period. Purvin & Gertz has reviewed our long
term crude oil supply agreement and believes the mechanism serves as a
suitable method of stabilizing coker gross margin fluctuations.
. Clark Refining & Marketing will offtake all the intermediate and final
products produced by our operations and will provide services to us on a
routine contractual basis. Clark Refining & Marketing will be able to
incorporate the products from our operations into the Port Arthur
refinery and has considerable experience in selling finished products
into the Gulf Coast market.
. The product offtake, operation, maintenance and other services provided
under the contracts between Clark Refining & Marketing and Port Arthur
Coker Company contemplate products and services that are priced to
reflect arms-length mechanisms and market-based prices and contain fair
market terms.
. Based on Purvin & Gertz's analysis of the worldwide heavy oil supply and
demand fundamentals and plans and objectives stated by PEMEX and the
Venezuelan national oil company, Purvin & Gertz forecasts that heavy
sour crude oil production will continue to increase through the term of
our financing. The crude oil heavy/light differential is forecast to
average $6.00 per barrel or above in constant 1999 dollars over the same
period. This is equivalent to a $15.16 per barrel coker gross margin as
defined by the differential formula in the long term crude oil supply
agreement. This forecast is consistent with the expectation that coker
projects will continue to develop in an orderly fashion in line with the
expected heavy sour crude oil production increases.
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<PAGE>
. P.M.I. Comercio Internacional and PEMEX have sufficient Maya reserves to
fulfill the supply obligation under our long term crude oil supply
agreement. The risk of diversion of Maya away from Port Arthur Coker
Company is thought to be minimal because:
. Mexico is increasing its production of Maya from 1.6 million
barrels per day to 2.0 million barrels per day;
. the number of other sour crude oil refineries able to process Maya
are very limited;
. the demand for heavy sour crude oil outside the United States is
small and Purvin & Gertz does not expect it to change during the
forecast period; and
. the netback for heavy sour crude oil shipments to Europe or Asia
is low relative to U.S. Gulf Coast deliveries.
. Although the refinery upgrade project is designed to process Maya as its
primary feedstock, it will have the flexibility to process other similar
quality heavy sour crude oils and will be able to achieve essentially
equivalent economics to the base case projections with minimal changes
to configuration excluding any benefits of the coker gross margin
guarantee in our long term crude oil supply agreement.
. The shutdown of the Port Arthur refinery is an extremely remote
possibility due to its competitiveness post-completion of the refinery
upgrade project.
. The terms of each of the product purchase agreement, the services and
supply agreement, the ground lease and the facility and site lease are
as favorable to Clark Refining & Marketing and to Port Arthur Coker
Company, in all material respects, as terms that would be obtainable at
this time for a comparable transaction or series of similar transactions
in arm's length dealings with a party who is not an affiliate. Payments
to be made by Clark Refining & Marketing to us under the product
purchase agreement and the services and supply agreement are fair
consideration for the products acquired or services received.
. The consideration we paid Clark Refining & Marketing for our assumption
of the long term crude oil supply agreement, our acquisition of work in
progress on our coker project and Clark Refining & Marketing's reduction
of the permissable emissions levels under one of its air emissions
permits in order to allow us to obtain our air permit was equal to the
fair market value of these assets. The rental payments Clark Refining &
Marketing received under the ground lease and will receive under the
facility and site lease are equal to the fair market value rental
payments of the property leased.
Financial Projections
. The Purvin & Gertz base case assumes that our new units are operated as
part of the Port Arthur refinery. Assuming a specified price forecast,
estimated average operating cash flow over our initial 11-year operating
period is approximately $228 million and the after-tax cash flows
generated by our operations will be sufficient to repay our debt
obligations, including scheduled principal amortization and interest,
with a minimum debt service coverage ratio of 2.0:1.0 and an average
debt service coverage ratio of 2.4:1.
. Purvin & Gertz analyzed various sensitivity cases including a backcast
from 1989 to 1998 and concluded that in all cases we can comfortably
meet our debt service obligations. The Independent Engineer's Report
annexed to this prospectus presents the backcast case from 1989 to 1996
because the senior debt has a term of eight years after start-up.
. The PMI surplus reserve account provides liquidity during low coker
margin periods, which is reflected in the backcast case with a minimum
debt service coverage ratio of almost 1.0:1.0 and an average debt
service coverage ratio of almost 2.0:1.0. In 2007 where debt service
shortfall amounts to $3.0 million, the PMI surplus reserve account is
fully funded with $50 million. In the backcast case without our long
term crude oil supply agreement in place, cash flow shortfall amounts to
$5.0 million, with a debt service reserve account of $37 million and
over $100 million of cash available for debt service.
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<PAGE>
. The PMI surplus reserve account effectively mitigates the timing issue
of a delay in receiving discounts after prior period surpluses. When
fully funded and combined with the debt service reserve account, these
reserve accounts provide up to 1.25 years of debt service coverage for
our senior debt.
. The proceeds of the total financing combined with the proposed equity
should be sufficient to pay our total estimated coker project cost.
. If the refinery upgrade project is designed, constructed, operated and
maintained as currently proposed, we should be capable of meeting or
exceeding the production projections.
. The basis for the estimate of our total costs of operating and
maintaining our heavy oil processing facility is in accordance with
standard industry practice. The operating and maintenance costs set
forth in the base case projections provide sufficient funds for the
operations and maintenance of our heavy oil processing facility is
consistent with the operating scenarios presented.
Stand-alone Case
To demonstrate the robustness of the economics of our operations and to
ensure that we can operate independently of Clark Refining & Marketing, Purvin
& Gertz developed a stand-alone case that assumes the following:
. We continue our operations while the rest of the Port Arthur refinery,
other than our heavy oil processing facility and the other facilities at
the refinery that we have a right to use, discontinues operations;
. We use the full capacity of our heavy oil processing facility;
. A third-party is operating our heavy oil processing facility;
. We continue to purchase crude oil under our long term crude oil supply
agreement;
. A third party is marketing all intermediate and finished products from
our heavy oil processing facility on our behalf; and
. Our rights to possession under the facility and site lease and the
ground lease remain in effect.
In this regard Purvin & Gertz has concluded that:
. From a technical standpoint, we could successfully continue to operate
in a stand-alone mode;
. The modifications necessary to achieve stand-alone operation are
relatively minor and could be achieved within three months;
. The intermediate and finished products produced by us during stand-alone
operation should be readily marketable based on appropriate discounts
for quality to spot market prices to long term off-takers since we are
located in the most liquid refinery products market in the world. These
discounts are applied to specified intermediate products over a 3 year
period to account for the market disruption caused by introducing a
large volume of intermediate products into the market; and
. Even in this extremely unlikely scenario, we will be able to service our
debt obligations after paying all operating expenses as evidenced by a
projected minimum after tax debt service coverage ratio of 1.1:1.0 and
average after tax debt service coverage ratio of 1.9:1.0.
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<PAGE>
CRUDE OIL AND REFINED PRODUCT MARKET REPORT SUMMARY
Selected conclusions of Purvin & Gertz's crude oil and refined product
market report are summarized below. This report is set forth in its entirety as
Annex C to this prospectus.
General
. The overall level of crude oil prices is set by the cost of production
and supply/demand pressures. If the price is too high, the supply will
increase because of the economic attractiveness of developing new
reserves or producing existing reserves at higher rates. At the same
time, demand is decreased by use of alternative fuels such as coal,
natural gas, or nuclear energy, and/or by conservation efforts. The
resulting imbalance of supply versus demand forces prices back down. In
the same manner, if the price is too low, demand is stimulated,
alternative energy supply development is constrained, and adding new
reserves becomes less economical. Ultimately, the low prices cause
demand to approach capacity limits on production, and the resulting
competition for supply drives prices back up.
. The absolute level of crude oil prices has a very direct impact on the
feasibility of the upstream business, but crude oil price differentials
have a larger impact on the economics of refinery conversion projects.
The heavy/light differential in this report is expressed as the
differential between West Texas Intermediate and Maya.
Heavy/Light Differential
. The heavy/light differential is the result of a complex balance of a
number of factors, such as absolute and relative demand for light and
heavy products, supply of heavy sour crude oil and conversion capacity
supply/demand balance.
. For the period from August 1987 to December 1998, the differential
averaged $5.70 per barrel based on Platt's Oilgram Price report weekly
quotes.
. For the period from January 1988 to March 1999, the six-month period
moving average of the heavy/light differential ranged from a high of
$8.90 per barrel to a low of $3.76 per barrel, heavy/light with an
average of $5.83 per barrel.
. Low oil prices and reduced supplies of heavy sour crude oil relative to
conversion capacity have caused the differential to narrow in late
1998/early 1999. Despite these adverse conditions, the heavy/light
differential averaged about $5.00 per barrel over the past six months.
. Purvin & Gertz expects the heavy/light differential to widen from 2000
to 2005, and then remain relatively stable for the remainder of the
forecast period. The differential will widen due to a number of factors,
such as:
. a rise in the price of crude oil. All other things being equal,
when the price of crude oil rises the heavy/light differential
will tend to widen;
. a resurgence of strong product demand in Asia, filling conversion
capacity; and
. an increase in the rate of development of heavy sour crude oil
reserves in Mexico, Venezuela, and Canada will rapidly increase
overall heavy feedstock availability and overwhelm conversion
capacity.
. The heavy/light differential over the 2000 to 2020 time period is
forecast to average $6.51 per barrel in real terms and $8.18 per barrel
in nominal terms. While there can be considerable volatility in the
heavy/light differential, the market fundamentals suggest a widening
heavy/light differential, which will be beneficial to us.
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<PAGE>
Heavy Crude Oil Availability
. Purvin & Gertz expects adequate supplies of heavy sour crude oil to be
available to us throughout the forecast period, given that heavy sour
crude oil production is concentrated in the Western Hemisphere and
expects production to increase substantially over the life of the
refinery upgrade project.
. Our heavy oil processing facility has been designed to process Maya
produced by PEMEX. Purvin & Gertz expects Maya to be abundant given
PEMEX's reserves, production levels and plans to expand production.
. If the Maya is diverted from us, there are alternative supplies.
Although most of the other heavy sour crude oil supplies are generally
heavier than Maya, there are still heavy sour crude oils that could be
used effectively in the new coker unit.
. contracts for Venezuela heavy sour crude oil could probably be
obtained since Venezuela plans to significantly increase its
supply of heavy sour crude oil after 2000.
. contracts for neutral zone crude oil could probably be obtained
since the producers Saudi Arabia and Kuwait are having difficulty
placing their growing supplies.
. The risk of diversion of the Maya contracted to be used in the Port
Arthur refinery is minimal for the following reasons:
. a program to significantly expand production of Maya is currently
underway and the extra supply will be difficult to place in the
market due to the limited capacity of complex refineries required
to process it;
. the netback for heavy sour crude oil shipments to Europe or Asia
is low related to U.S. Gulf Coast deliveries; and
. heavy sour crude oil is run in complex high conversion refineries
and the highest concentration of this type of refinery is found in
the U.S. Gulf Coast.
. The demand for heavy sour crude oil outside the United States is small
and relates primarily to asphalt manufacture, Purvin & Gertz does not
expect this to change during the forecast period.
. About 75% of the refinery capacity in the U.S. East Coast, Midwest and
Southwest is designed for light sweet and light sour crude oil. The
light sweet refineries can not run heavy, high sulfur crude oil like
Maya due to metallurgy and product specifications. The light sour
refineries already run as heavy a mix of crude oil as is practical.
. A heavy sour crude oil producer with an equity position in a refinery
will choose to run its own crude oil rather than purchasing from others
such as Mexico. PDVSA, the Venezuelan national oil company, has equity
ownership of over 900,000 barrels per day of refining capacity in the
United States which equals about 30% of the total heavy oil refinery
capacity in the U.S. East Coast, Midwest and Southwest, and is following
an aggressive strategy to secure markets for its heavy sour crude oil in
competition with Mexico.
. Although Mexico could decide to participate in heavy sour crude oil
export cutbacks, the cutbacks are not likely to be large and would be
prorated over all of its customers. Recently announced cutbacks have
been in the 100,000 to 125,000 barrels per day range or about 10% of
exports. The refinery upgrade project would not be materially affected
by cuts of this magnitude.
Product Demand
. Product demand growth varies from year to year but generally averages
less than 2% annually. Gasoline growth is the key to overall product
growth since it accounts for 40% to 50% of the total. Jet fuel is the
fastest growing product but total demand is relatively small.
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Refinery Margins
. Purvin & Gertz expects refinery margins for heavy sour crude oil
processors to be significantly higher than for light sweet crude oil
refineries. The refinery upgrade project will move the Port Arthur
refinery into the top tier of Gulf Coast refineries.
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SECURITY OWNERSHIP OF OWNERS
Port Arthur Finance
All of the outstanding capital stock of Port Arthur Finance is owned by Port
Arthur Coker Company.
Port Arthur Coker Company
The following table sets forth information concerning the owners of Port
Arthur Coker Company.
<TABLE>
<CAPTION>
Percent
Nature of of Percent of Total
Name and Address Ownership Interest Ownership Voting Power
---------------- ------------------ --------- ----------------
<S> <C> <C> <C>
Sabine River Holding
Corp. .................... General Partner 1% 100%
1801 S. Gulfway Drive,
Office No. 36
Port Arthur, Texas 77640
Neches River Holding
Corp. .................... Limited Partner 99%(1) 0%
c/o The Corporation Trust
Company
1209 Orange Street
Wilmington, DE 19801
</TABLE>
- --------
(1) All the outstanding capital stock of Neches River Holding Corp. is owned by
Sabine River Holding Corp.
Sabine River
The following table sets forth information concerning the owners of Sabine
River.
<TABLE>
<CAPTION>
Number of Percent Percent of Total
Name and Address Title of Class Shares of Class Voting Power
---------------- -------------- --------- -------- ----------------
<S> <C> <C> <C> <C>
Clark Refining Holdings
Inc..................... Common 6,136,364 90% 90%
Occidental Petroleum Cor-
poration................ Common 681,818 10% 10%
</TABLE>
Clark Refining Holdings
The following table and the accompanying notes set forth information
concerning the beneficial ownership of the common stock and Class F common
stock of Clark Refining Holdings:
. each person who is known by us to own beneficially more than 5% of the
common stock of Clark Refining Holdings;
. each director and each executive officer who is the beneficial owner of
shares of common stock of Clark Refining Holdings; and
. all directors and executive officers as a group.
<TABLE>
<CAPTION>
Number of Percent Percent of Total
Name and Address Title of Class Shares of Class Voting Power(/1/)
---------------- -------------- ---------- -------- -----------------
<S> <C> <C> <C> <C>
Blackstone Management
Associates III
L.L.C.(2) ............. Common 19,975,374 98.3% 78.8%
Occidental Petroleum
Corporation............ Class F Common 6,101,010 100.0% 19.9%
All directors and execu-
tive
officers as a group(2). Common 20,041,030 98.7% 79.0%
</TABLE>
- --------
(1) Represents the total voting power of all shares of common stock
beneficially owned by the named stockholder.
(2) The 19,975,374 shares held by Blackstone are directly held as follows:
15,937,378 shares by Blackstone Capital Partners III Merchant Banking Fund
L.P., 2,839,468 shares by Blackstone Offshore Capital Partners III L.P. and
1,198,528 shares by Blackstone Family Investment Partnership III L.P., of
each of which Blackstone Management Associates III L.L.C. is the general
partner having voting and dispositive power. Robert L. Friedman, a director
of Port Arthur Finance, Sabine River and Neches River is a member of
Blackstone Management Associates III, which has investment and voting
control over the shares held or controlled by Blackstone. Messrs. Peter G.
Peterson and Stephen A. Schwarzman are the founding members of Blackstone
and as such may also be deemed to share beneficial ownership of the shares
held or controlled by Blackstone. Each of such persons disclaims beneficial
ownership of such shares.
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OWNERSHIP STRUCTURE AND RELATED PARTY TRANSACTIONS
Ownership Structure
Port Arthur Coker Company was formed to construct and own our coker project,
lease the ancillary equipment and operate and maintain our heavy oil processing
facility. Port Arthur Finance is a wholly owned subsidiary of Port Arthur Coker
Company whose purpose is to facilitate the financing activities of Port Arthur
Coker Company. Under an agency agreement with, and an intercompany note from,
Port Arthur Coker Company, Port Arthur Finance issued the outstanding notes and
borrowed monies under our bank credit facilities on behalf of Port Arthur Coker
Company and transferred the proceeds of the issuance of the outstanding notes
and is obligated to transfer borrowings under our bank credit facilities to
Port Arthur Coker Company.
Port Arthur Coker Company is owned 1% by our sole general partner, Sabine
River, and 99% by our sole limited partner, Neches River, a wholly owned
subsidiary of Sabine River. Both Sabine River and Neches River were formed
specifically for the purpose of holding our partnership interests. Occidental
and Clark Refining Holdings own 10% and 90%, respectively, of Sabine River. As
of February 29, 2000, Clark Refining Holdings was owned indirectly through
subsidiaries, by Blackstone through an approximately 78.8% voting interest,
which represents a 75.6% economic interest, and by Occidental through an
approximately 19.9% voting interest, which represents a 23.1% economic
interest.
Sabine River Stockholders' Agreement
Clark Refining Holdings and Occidental have entered into a stockholders'
agreement. This agreement restricts the ownership and transfer of shares of
Sabine River and provides a right of first refusal for the benefit of Clark
Refining Holdings in the event that Occidental wishes to transfer its shares of
Sabine River. The Sabine River stockholders' agreement also provides Occidental
with the right to designate one member of the Sabine River board of directors
as long as Occidental maintains a specified ownership level in Sabine River.
The Sabine River stockholders' agreement grants additional rights to
Occidental, including rights for Occidental to participate on an equal and
ratable basis in the case of transfers of shares of Sabine River by Clark
Refining Holdings. In addition, it provides Clark Refining Holdings with the
right to require Occidental to sell its shares, on the same terms and
conditions as Clark Refining Holdings, in the case of a sale by Clark Refining
Holdings of all of its shares in Sabine River.
The Sabine River stockholders' agreement provides that, if the board of
directors of Sabine River determines, upon advice of its counsel, that it is no
longer necessary for us, Sabine River and Neches River to be bankruptcy remote,
Occidental may elect to exchange or may be required to exchange shares of
common stock of Sabine River it owns for Class F Common Stock, par value $.01
per share, of Clark Refining Holdings.
Transaction Fee
When we issued the outstanding notes, we used a portion of the proceeds of
our senior debt and equity contributions to pay Clark Refining Holdings
approximately $8 million for services provided to us by Blackstone Management
Partners III L.L.C. in connection with the raising of equity for and
structuring of our coker project, and Clark Refining Holdings will pay such fee
to Blackstone Management Partners III L.L.C. at such time and in such manner as
they may agree.
Transfer Restrictions Agreement
We, Sabine River, Neches River, Clark Refining Holdings and Blackstone have
agreed with the agent for the bank lenders, the agent for oil payment insurers
and the indenture trustee, that none of us, Sabine River, Neches River, Clark
Refining Holdings or Blackstone will effect, or permit any affiliate to effect,
any transfer of such party's direct or indirect interest, if any, in us, Clark
Refining & Marketing or the Port Arthur refinery except in limited situations.
These restrictions are described in greater detail under the caption
"Description of Our Principal Financing Documents--Transfer Restrictions
Agreement" in this prospectus.
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Our Relationship with Clark Refining & Marketing
We are an affiliate of Clark Refining & Marketing because our parent company,
Clark Refining Holdings, owns 100% of the capital stock of Clark USA, which in
turn owns 100% of the capital stock of Clark Refining & Marketing.
Clark Refining & Marketing formally initiated the refinery upgrade project in
April 1998 after entering into the long term crude oil supply agreement with
P.M.I. Comercio Internacional. Construction commenced in September 1998. When
we issued the outstanding notes, we acquired the work in progress on our coker
project for $157.1 million. We also paid Clark Refining & Marketing
approximately $2 million for the assumption of the long term crude oil supply
agreement, transfer of employees and its reduction of the permissible emissions
levels under one of its air emissions permits in order to allow us to obtain
our air permit.
During the operating period, Clark Refining & Marketing will be obligated to
accept and pay for all our products that we tender for delivery under the
product purchase agreement. Clark Refining & Marketing will also provide
operations and maintenance services and will supply required feedstocks for the
operation of our heavy oil processing facility under the services and supply
agreement. We are leasing the site of our coker project from Clark Refining &
Marketing on a long term basis and have prepaid the entire rental amount of
$25,000. We are also leasing some ancillary units and equipment and have
obtained some related easements from Clark Refining & Marketing, for which we
will pay them a quarterly rent and a monthly operating fee subject to some
adjustments under the facility and site lease beginning at start-up of our
heavy oil processing facility. Under this lease, Clark Refining & Marketing is
also obligated to undertake modifications and additions to the equipment we are
leasing. The terms of the agreements referred to in this paragraph are
described under the caption "Description of Our Principal Project Documents."
In the opinion of Purvin & Gertz, the terms of each of the product purchase
agreement, the services and supply agreement, the ground lease and the facility
and site lease are as favorable to Clark Refining & Marketing and to Port
Arthur Coker Company, in all material respects, as terms that would be
obtainable at this time for a comparable transaction or series of similar
transactions in arm's length dealings with a person who is not an affiliate. In
the opinion of Purvin & Gertz, payments to be made by Clark Refining &
Marketing to us under the product purchase agreement and the services and
supply agreement are fair consideration for the products acquired or services
received.
In the opinion of Purvin & Gertz, the consideration we paid Clark Refining &
Marketing for our assumption of the long term crude oil supply agreement, our
acquisition of work in progress under the construction contract and Clark
Refining & Marketing's reduction of the permissible emissions levels under one
of its air emissions permits in order to allow us to obtain our air permit is
equal to the fair market value of these assets. According to Purvin & Gertz,
Clark Refining & Marketing the rental payments under both the ground lease and
the facility and site lease are equal to the fair market value rental payments
of the property leased.
Tax Sharing Agreement
Sabine River and Neches River will file a consolidated U.S. federal income
tax return together with Clark Refining Holdings and its other consolidated
subsidiaries. Sabine River and Neches River have entered into a tax sharing
agreement with Clark Refining Holdings and the other members of its
consolidated group pursuant to which they have each agreed to pay to Clark
Refining Holdings their respective share of the Clark Refining Holdings
consolidated group's federal income tax liability, which will be determined on
a separate return basis. Similar provisions also will apply for any state or
local jurisdictions in which we file on a consolidated, combined or unitary
basis together with Clark Refining Holdings or any other member of the Clark
Refining Holdings' group.
Clark Refining Holdings will continue to have all the rights of a parent of a
consolidated group and similar rights provided for by applicable state and
local law, will be the sole and exclusive agent for Sabine River and
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Neches River in any and all matters relating to their consolidated, combined or
unitary income or franchise tax liabilities. In addition, it will have sole and
exclusive responsibility for the preparation and filing of consolidated federal
income tax returns and will have the power, in its sole discretion, to contest
or comprise any asserted tax adjustment or deficiency and to file, litigate or
compromise any claim for refund on our behalf related to such return. During
the period in which Sabine River and Neches River are included in the Clark
Refining Holdings' consolidated group, Sabine River and Neches River could be
liable in the event that any federal tax liability is incurred, but not
discharged, by any other member of the Clark Refining Holdings' consolidated
group.
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PRINCIPAL PROJECT PARTICIPANTS
Except in the case of Blackstone and Clark Refining & Marketing, the
following information is based solely on and derived solely from publicly
available documents which such entities filed with the Securities and Exchange
Commission, such as their annual reports on Form 10-K and quarterly reports on
Form 10-Q and, in the case of PEMEX, its annual report on Form 20-F. These
documents are available to the public and can be inspected and copied at the
public reference facilities maintained by the Commission in Washington, D.C. We
have not conducted any independent investigation of these entities and
therefore cannot assure you of the accuracy or completeness of such
information.
The Blackstone Group L.P.
The Blackstone Group L.P. is a private investment bank based in New York and
was founded in 1985 by its current Chairman, Peter G. Peterson, former Chairman
and CEO of Lehman Brothers and a former U.S. Secretary of Commerce, and its
current President and Chief Executive Officer, Stephen A. Schwarzman, former
Chairman of Lehman Brothers' Mergers & Acquisitions Committee. The Blackstone
Group's main businesses include private equity investing, merger and
acquisition advisory services, restructuring advisory services, real estate
investing, mezzanine investing and asset management.
The firm's current corporate private equity investment vehicle is Blackstone
Capital Partners III, which was the largest private equity fund of its type
raised in 1997 with approximately $4 billion of committed equity capital.
Blackstone Capital Partners III is comprised of Blackstone Capital Partners III
Merchant Banking Fund L.P., a Delaware limited partnership, Blackstone Offshore
Capital Partners III L.P., a Cayman Islands limited partnership and Blackstone
Family Investment Partnership III L.P., a Delaware limited partnership.
Beginning with Blackstone Capital Partners I in 1987, Blackstone, together with
its affiliates, has invested or committed approximately $3.5 billion of equity
in 41 transactions having an aggregate transaction value of approximately $35.2
billion.
Blackstone has invested in a number of diverse businesses and industries
including heavy industrial businesses, such as steel, automotive, high
performance alloys, other manufacturing businesses, such as packaging, toys,
wallpaper, cable TV, cellular, service industries, such as financial services,
food services and funeral homes, and transportation, among others. Blackstone
has been a leader in using the private equity investment format of the
"corporate partnership," a joint venture acquisition between operating
companies and Blackstone's principal funds.
Blackstone acquired its interest in the predecessor of Clark Refining
Holdings for $134 million in November 1997 and is committed to invest
approximately $122 million in Clark Refining Holdings as part of our coker
project. As of February 29, 2000, Blackstone had contributed $55.3 million
towards this commitment as described under "Financing Plan--Equity
Contributions and Commitments." This investment has made Clark Refining
Holdings one of Blackstone's largest investments.
Occidental
Occidental explores for, develops, produces and markets crude oil and natural
gas and manufactures and markets a variety of basic chemicals, including
chlorine, caustic soda and ethylene dichloride (EDC), as well as specialty
chemicals. Occidental conducts its principal operations through two
subsidiaries, Occidental Oil and Gas Corporation and Occidental Chemical
Corporation. Occidental has an interest in the vinyls intermediates business,
including polyvinyl chloride (PVC) and vinyl chloride monomer (VCM), through
its 76% interest in the Oxy Vinyls, LP partnership. Occidental also has an
interest in the petrochemicals business through its 29.5% interest in the
Equistar Chemicals, LP partnership. For the fiscal year ended December 31,
1998, Occidental had $6,596 million in net sales and operating revenues, $325
million in income from continuing operations and $363 million in net income. As
of September 30, 1999, Occidental had total assets of $14,135 million with
stockholders' equity of $3,216 million. Occidental is a Delaware corporation.
Occidental acquired its interest in the predecessor of Clark Refining
Holdings in exchange for rights to future crude oil deliveries that Clark
Refining & Marketing subsequently sold and is committed to invest
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approximately $14 million in Sabine River as part of our coker project. As of
February 29, 2000, Occidental had contributed $6.1 million towards this
commitment as described under "Financing Plan--Equity Contributions and
Commitments."
Clark Refining & Marketing
Clark Refining & Marketing is currently one of the five largest independent
refiners of petroleum products in the United States based on rated crude oil
throughput capacity. Clark Refining & Marketing is a wholly owned subsidiary of
Clark USA, which is a wholly owned subsidiary of Clark Refining Holdings. Clark
Refining & Marketing's four refineries, the Port Arthur refinery, two
refineries in Illinois and one in Ohio, represent an aggregate of over 547,000
barrels per day of rated crude oil throughput capacity. Clark Refining &
Marketing is pursuing a strategy of focusing on refining operations which it
believes will offer higher potential returns. As part of this strategy, in July
1999 Clark Refining & Marketing disposed of its retail operations for gross
proceeds of approximately $230 million and in December 1999, sold fifteen
product terminals for $35 million plus working capital. As of December 31,
1999, Clark Refining & Marketing had $794.9 million of long-term debt
outstanding. For more information regarding Clark Refining & Marketing you
should read the section of this prospectus captioned "Available Information"
and Annex A to this prospectus.
Foster Wheeler Corporation and Foster Wheeler USA
One of the principal businesses of Foster Wheeler Corporation and its
subsidiaries is the design, engineering and construction of petroleum,
chemical, petrochemical and alternative-fuels facilities and related
infrastructure, including power generation and distributing facilities,
production terminals, pollution control equipment and water treatment
facilities and process plants for the production of fine chemicals,
pharmaceuticals, dyestuff, fragrances, flavors, food additives and vitamins.
For the fiscal year ended December 25, 1998, Foster Wheeler Corporation had
$4,597 million in revenues, $47.8 million in earnings before income taxes and
$31.5 million in net losses. As of September 24, 1999, Foster Wheeler
Corporation had total assets of $3,326.3 million with stockholder's equity of
$531.3 million. Foster Wheeler Corporation is a New York corporation.
Foster Wheeler USA is a wholly owned subsidiary of Foster Wheeler
Corporation. Foster Wheeler USA is not subject to the informational
requirements of the Securities Exchange Act of 1934. The obligations of Foster
Wheeler USA under our construction contract are guaranteed by Foster Wheeler
Corporation.
You should refer to Foster Wheeler's publicly available documents, including
its Form 10-K and Form 10-Qs, for further information as to its results of
operations and financial condition in evaluating the construction contract it
has entered into with PACC.
PEMEX and P.M.I. Comercio Internacional
PEMEX is the largest company in Mexico and one of the largest in the world.
Since 1938, Mexican federal laws and regulations have entrusted PEMEX with the
central planning and management of Mexico's petroleum industry. According to
Petroleum Intelligence Weekly, December 14, 1998, PEMEX is the sixth largest
oil and gas company in the world and the second largest in the Americas,
accounting for nearly 5% of the world's crude oil and condensates production in
1997. In 1998, PEMEX, through P.M.I. Comercio Internacional, sold 1,712
thousand barrels per day of crude oil. PEMEX is a supplier of crude oil to the
United States.
P.M.I. Comercio Internacional, P.M.I. Trading Ltd. and their affiliates
provide PEMEX and a number of independent customers with international trading,
distribution and related services. P.M.I. Comercio Internacional and P.M.I.
Trading Ltd. sell, buy and transport crude oil, refined products and
petrochemicals in world markets. The trading volume of sales and imports of
P.M.I. Comercio Internacional, P.M.I. Trading Ltd. and their affiliates totaled
$9.0 billion in 1998, including $6.4 billion in crude oil sales.
P.M.I. Comercio Internacional has entered into several long term crude oil
supply agreements, including its long term crude oil supply agreement with us,
pursuant to which the purchasers have agreed to undertake
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projects to expand the capacity of their respective refineries to upgrade
residue from Maya. These long term crude oil supply agreements further PEMEX's
strategy to support the export value of Maya in relation to the value of other
grades of crude oil by creating incentives for refiners to invest in new high-
conversion refineries that will be capable of upgrading the relatively large
portion of residue produced from processing Maya in less efficient refining
complex configurations.
Based on its annual report on Form 20-F filed with the Commission, as of
December 31, 1998, as based on an established exchange rate for accounting
purposes of Ps. 9.8650 = U.S.$1.00 at December 31, 1998, PEMEX had total assets
of $42,896 million with equity of $17,599 million, both calculated in
accordance with Mexican generally accepted accounting principles; the amount of
PEMEX's equity calculated in accordance with U.S. generally accepted accounting
principles as of December 31, 1998 was approximately $3,170 million. For the
fiscal year ended December 31, 1998, PEMEX had total revenues of $26,939
million and net losses of $1,028 million, both calculated in accordance with
Mexican generally accepted accounting principles; the amount of PEMEX's net
losses for fiscal year ended December 31, 1998 calculated in accordance with
U.S. generally accepted accounting principles was approximately $2,623 million.
According to its annual report on Form 20-F filed with the Commission, as of
December 31, 1998, PEMEX had proved developed reserves of 12,059 million
barrels of crude oil and natural gas liquids, determined under the Society of
Petroleum Engineers' and World Petroleum Congress' definitions.
P.M.I. Comercio Internacional is not subject to the informational
requirements under the Securities Exchange Act of 1934. The obligations of
P.M.I. Comercio Internacional under our long term crude oil supply agreement
are guaranteed by PEMEX.
You should refer to PEMEX's publicly available documents, including its Form
20-F, for further information as to its results of operations and financial
condition in evaluating the long term crude oil supply agreement.
Air Products
Air Products has established an internationally recognized industrial gas and
related industrial process equipment business and developed strong positions as
a producer of certain chemicals. The industrial gases business segment of Air
Products recovers and distributes industrial gases such as oxygen, nitrogen,
argon and hydrogen and a variety of medical and specialty gases. Based on its
current report filed with the Commission on Form 10-K for the fiscal year ended
September 30, 1999, Air Products had $5,020.1 million in sales, $724.7 million
in operating income and $450.5 million in net income. As of September 30, 1999,
Air Products had total assets of $8,235.5 million with total shareholders'
equity of $2,961.6 million. Air Products is a Delaware corporation.
In July 1999, Air Products announced that its board and the boards of L'Air
Liquide S.A. of France and the BOC Group plc, a British industrial gases
company, had agreed to the terms of a recommended offer under which Air
Products and Air Liquide will acquire BOC. The offer will formally commence in
the United States and the United Kingdom upon receipt of the necessary
regulatory approvals, which Air Products expects to occur in the first quarter
of the year 2000.
You should refer to Air Product's publicly available documents, including its
Form 10-K and Form 10-Qs, for further information as to its results of
operations and financial condition in evaluating the hydrogen supply contract
agreement.
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MANAGEMENT
Directors and Executive Officers
The following table provides information concerning the directors and
executive officers of Port Arthur Finance, Sabine River and Neches River. The
control, management and operation of Port Arthur Coker Company is vested in its
general partner, Sabine River, pursuant to a partnership agreement.
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C> <C>
William C. Rusnack...... 55 President and Chief Executive Officer, Director
Maura J. Clark.......... 41 Executive Vice President and Chief Financial Officer
David I. Foley.......... 32 Director
William E. Haynes....... 56 Director
Robert L. Friedman...... 56 Director
Stephen I. Chazen....... 53 Director
</TABLE>
William C. Rusnack was appointed President and Chief Executive Officer and a
Director of Sabine River and Neches River in May 1999, and Port Arthur Finance
in August 1999. He has served as President, Chief Executive Officer, Chief
Operating Officer and a Director of Clark Refining & Marketing and Clark USA
since April 1998, and of Clark Refining Holdings since April 1999. Mr. Rusnack
previously served 31 years with Atlantic Richfield Corporation and was involved
in all areas of its energy business, including refining operations, retail
marketing, products transportation, exploration and production, and human
resources. He most recently served as President of ARCO Products Company from
1993 to 1997 and was President of ARCO Transportation Company from 1990 to
1993. He has served as a Director of Flowserve, a NYSE listed corporation,
since 1993.
Maura J. Clark was appointed Executive Vice President and Chief Financial
Officer of Sabine River and Neches River in May 1999, and Port Arthur Finance
in August 1999. Ms. Clark also served as a Director of Sabine River and Neches
River from May 1999 through July 1999. She has served as Executive Vice
President--Corporate Development and Chief Financial Officer of Clark Refining
& Marketing and Clark USA since August 1995, and of Clark Refining Holdings
since April 1999. Ms. Clark previously served as Vice President--Finance at
North American Life Assurance Company, a financial services company, from
September 1993 through July 1995.
David I. Foley was appointed Director of Sabine River and Neches River in May
1999, and Port Arthur Finance in August 1999. He has served as a director of
Clark Refining & Marketing and Clark USA since November 1997, and of Clark
Refining Holdings since April 1999. Mr. Foley is a Vice President at The
Blackstone Group L.P., which he joined in 1995. Prior to joining Blackstone,
Mr. Foley was a member of AEA Investors, Inc. and The Monitor Company. He
currently serves on the board of directors of Rose Hills Company.
William E. Haynes was appointed Vice President and a Director of Port Arthur
Finance, Sabine River and Neches River in August 1999. He served as Chairman,
Chief Executive Officer and a Director 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
1977. 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 currently serves on the board of directors of Philip
Services Corp. and Innovative Valve Technologies Inc.
Robert L. Friedman was appointed a Director of Port Arthur Finance, Sabine
River and Neches River in July 1999. Mr. Friedman has served as a Senior
Managing Director of The Blackstone Group L.P. since March 1999. Prior to
joining Blackstone, Mr. Friedman was an attorney with Simpson Thacher &
Bartlett, a New York law firm, since 1967. He was a partner of Simpson Thacher
from 1974 to 1999 and a member of its
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executive committee for most of that period. Mr. Friedman currently serves on
the board of directors of American Axle & Manufacturing, Inc., Clark Refining
Holdings, Corp Group and Republic Technologies, Inc.
Stephen I. Chazen was appointed a Director of Sabine River, Neches River and
Port Arthur Finance in July 1999. He has served as a Director of Clark Refining
Holdings since April 1999 and of Clark USA since December 1995. Mr. Chazen has
been Executive Vice President--Corporate Development and Chief Financial
Officer of Occidental Petroleum Corporation since February 1999 and Executive
Vice President--Corporate Development since May 1994. Prior to May 1994, Mr.
Chazen served in various capacities at Merrill Lynch & Co., most recently as
Managing Director. Mr. Chazen currently serves on the Governance Committees of
Equistar Chemicals L.P. and Oxy Vinyls, L.P.
Under the certificates of incorporation of each of Port Arthur Finance,
Sabine River and Neches River each of their boards 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 Clark Refining & Marketing or its
affiliates, other than Blackstone, Occidental, Port Arthur Finance, Port Arthur
Coker Company, Sabine River or Neches River. The certificates of incorporation
of these companies also require that each of Port Arthur Finance, Sabine River
and Neches River have a senior 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 Port Arthur Finance, Sabine
River and Neches River. You should read the section captioned "Special Legal
Aspects" for information regarding the additional steps we have taken to ensure
our independence from Clark Refining & Marketing.
In addition, under the Sabine River stockholders' agreement Occidental has
the right to designate one member of the Sabine River board of directors as
long as it maintains a specified ownership level in Sabine River. Mr. Chazen
was designated by Occidental to serve on the board of directors of Sabine
River. The terms of the stockholders agreement are discussed in "Ownership
Structure and Related Party Transactions--Sabine River Stockholders'
Agreement."
Compensation and Employment Contracts
All directors are reimbursed for their reasonable expenses incurred in
attending board and committee meetings. Mr. Haynes has agreed to compensation
equal to $10,000 per year plus an additional fee of $2,500 for each day he
attends meetings or is otherwise performing his duties as a director, including
preparation for the performance of his duties prior to his appointment as
director. We are still in our pre-operation stage and did not exist during
1998. As a result, none of our directors or executive officers received any
compensation or any benefits from us during 1998. During 1999, Mr. Haynes has
received $12,500 in compensation related to his duties as a director.
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DESCRIPTION OF OUR PRINCIPAL PROJECT DOCUMENTS
The following is a summary of the material provisions of the principal
documents related to our coker project. A copy of each of these agreements has
been filed as an exhibit to the registration statement of which this prospectus
is a part. Unless otherwise stated, any reference in this prospectus to any
agreement means such agreement and all schedules, exhibits and attachments to
such agreements, as amended, supplemented or otherwise modified in effect as of
the date hereof.
Long Term Crude Oil Supply Agreement
Clark Refining & Marketing entered into a long term crude oil supply
agreement with P.M.I. Comercio Internacional in March 1998, which was amended
prior to the issuance of the outstanding notes. Simultaneously with the
issuance of the outstanding notes, all the rights and obligations of Clark
Refining & Marketing under this long term crude oil supply agreement, including
the obligation to undertake the refinery upgrade project, were assigned to Port
Arthur Coker Company.
In March 1998 PEMEX entered into a performance guarantee for the benefit of
Clark Refining & Marketing or any assignee thereof under the long term crude
oil supply agreement. Under such performance guarantee, PEMEX has
unconditionally and irrevocably guaranteed the obligations of P.M.I. Comercio
Internacional under the long term crude oil supply agreement.
Purchase and Sale of Maya
We are obligated to buy Maya from P.M.I. Comercio Internacional, and P.M.I.
Comercio Internacional is obligated to sell us Maya. All Maya bought and sold
under our long term crude oil supply agreement is solely for processing by us
at the Port Arthur refinery. Under the long term crude oil supply agreement,
the purchase and acceptance of delivered Maya is referred to as "lifting."
These purchase and sale obligations are determined differently in a start-up
period, a guarantee period and a phase out period. During these periods the
quantity of Maya available to us is described below.
Quantity of Maya Available to Us
Start-Up Period. The start-up period is the period beginning the first day of
the month in which we expect to first introduce feedstock into the new delayed
coking unit and ending on the last day of the month in which completion of the
refinery upgrade project is achieved as described below under "--The Refinery
Upgrade Project--Obligation to Complete the Refinery Upgrade Project."
During the start-up period, the quantity available is the amount of heavy
sour crude oil that we determine we need for start-up and operation of our new
delayed coking unit and our other facilities at the Port Arthur refinery less
the "current capacity decrease" which is 23,553 barrels per stream day. The
current capacity decrease represents the decrease in the amount of heavy sour
crude oil that will be processed through the cokers in service at the time the
long term crude oil supply agreement was signed. The determining periods used
for comparison are March 1997 through December 1997 and the period beginning
with the first month of the start-up period.
Guarantee Period. The guarantee period begins on the earliest date to occur
of the following and ends eight years thereafter:
. the first day following the start-up period;
. the scheduled completion date of January 2001, as such date may be
extended as described below under "--The Refinery Upgrade Project--
Obligation to Complete the Refinery Upgrade Project"; and
. the guarantee date of July 2001.
The July 2001 guarantee date can be extended for specified events of force
majeure or other acts or events that are beyond our reasonable control, not the
result of our fault or negligence, and that we have not been able to overcome
by exercising reasonable efforts, including spending funds. Our ability to
extend such date due to reason of force majeure, however, is limited to a total
of 365 days.
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During the guarantee period, the formula used to determine the quantity of
Maya available to us is as follows: (1) the operating capacity, multiplied by
the "coker fraction" of 0.879, and divided by 0.366 minus (2) 23,553. Operating
capacity is reset every six months and is the average daily volume of
feedstocks processed through the new delayed coking unit during the preceding
six months as stated in an officer's certificate from us. The coker fraction
represents the percentage of the design capacity of our new coking unit
designated for processing feedstocks from heavy crude oil.
If during the guarantee period our requirements for heavy sour crude oil for
processing at the Port Arthur refinery through the new delayed coking unit
exceed the sum of (1) the quantity as determined in the previous paragraph plus
(2) 23,553, then we may notify P.M.I. Comercio Internacional of the excess and
our proposed lifting program for the month. Thereafter, the quantity of Maya
available will be the greater of the quantity for the first month following
such notice and the quantity as determined according to the previous paragraph.
Extension of Guarantee Period. If an event of force majeure affecting the
delivery, lifting or processing of Maya results in a curtailment of processing
at the Port Arthur refinery of more than 25% of the amount of Maya available on
average over any period of 15 or more consecutive days during the guarantee
period, then the guarantee period will be extended by the number of days
necessary for the Port Arthur refinery to process the quantity of Maya not
processed due to such curtailment. If such event of force majeure is a
governmental force majeure, as described below under "--Force Majeure--Purchase
and Sale Related" and no part of the reduction of Maya to be sold and delivered
to us is not applied first to reduce quantities of Maya under other crude oil
supply agreements with us or any of our affiliates, then the 25% threshold
described in the preceding sentence will not be a condition to the extension of
the guarantee period. The aggregate period of all extensions described in this
paragraph cannot exceed 270 days in respect of events of force majeure
affecting the production or delivery of Maya by P.M.I. Comercio Internacional
or the loading terminal facilities, and 365 days in respect of events of force
majeure affecting the lifting, transportation, storage or processing of Maya by
us.
Phase Out Period. After the guarantee period, the quantity of Maya available
will be the amount available in the final month of the guarantee period, as
such amount may be phased out. After the guarantee period, each party has the
option of permanently reducing the amount of Maya available in any month under
the long term crude oil supply agreement upon at least three months prior
notice to the other party. The monthly amount available under the long term
crude oil supply agreement, however, may not be reduced in any three-month
period by more than 25% of the amount available for the last month of the
guarantee period. Moreover, the amount available in any month may not be
reduced to less than 25% of the amount available for the last month of the
guarantee period while any credit or premium remains to be applied to purchases
of Maya due to a shortfall or surplus in differentials described below under
"--Differential Formula and Guarantee."
Remedies for Underlifting
If we lift less than the amount of Maya available in any month, we are
obligated to pay to P.M.I. Comercio Internacional 15% of the regular price,
which is described below under "--Price of Oil," multiplied by the number of
barrels of Maya "underlifted" that month. We, however, will not be liable for
underlifting to the extent that underlifting of the available amount in any
month results from any of the following:
. operational inability of the Port Arthur refinery to process such amount;
. demonstrated operational reasons concerning loading terminals or tankers,
if the underlifted amount does not exceed 10% of such amount;
. our remedial work or an annual turnaround, if we give P.M.I. Comercio
Internacional the required notice;
. our previous lifting of an amount greater than the available amount in
anticipation of the weather interrupting the supply;
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. force majeure as described below under "--Force Majeure--Purchase and
Sale Related"; or
. underdelivery by P.M.I. Comercio Internacional or our actions in response
to an underdelivery by P.M.I. Comercio Internacional.
P.M.I. Comercio Internacional may terminate the long term crude oil supply
agreement because we underlifted only if we underlifted because we purchased
oil in substitution of Maya or because of our failure to pay the amount due for
underlifting. We are liable to P.M.I. Comercio Internacional for any resulting
damages due to such termination subject to the limitations on liability
described below. If we suspend or reduce the amounts that we lift, P.M.I.
Comercio Internacional will not be required to resume delivery of such amount
for three months or the period of suspension, whichever is shorter.
Underdelivery by P.M.I Comercio Internacional
P.M.I. Comercio Internacional is required to maintain the contractual right
to buy Maya from Pemex Exploracion y Produccion for sale to us and the right to
use specified loading terminals for delivering Maya to us. If P.M.I. Comercio
Internacional suspends or reduces its deliveries of Maya, we are not obligated
to resume lifting of such underdelivered amount for three months or the period
of suspension or reduction, whichever is shorter.
Price of Oil
The price of Maya supplied to us will either be the regular price subject to
adjustments as a result of the differential formula calculation or the price
determined by the alternative pricing mechanism described below.
Regular Price. The regular price per barrel in U.S. dollars is determined by
a formula that is equal to:
. 40% of the average of the Platt's prices for West Texas sour crude oil
for a specified five-day period; plus
. 40% of the average of the Platt's prices for no. 6 fuel oil having 3%
sulfur content for such five-day period; plus
. 10% of the average of the Platt's prices for light Louisiana sweet crude
oil for such five-day period; plus
. 10% of the average of the Platt's prices for Brent crude oil for such
five-day period; minus
. a pricing adjustment which is currently $3.50.
This formula and actual dollar value of the price adjustment are subject to
adjustment by P.M.I. Comercio Internacional.
For West Texas sour and light Louisiana sweet crude oils, the "Platt's Price"
for any day is the average of the high and low spot prices for such crude oils
as quoted for that day in Platt's Crude Oil Marketwire (Spot Assessment
Section). For Brent crude oil, the Platt's Price for any day is the average of
the high and low spot prices for Brent crude oil as quoted in Platt's Crude Oil
Marketwire (Spot Assessment Section). The quotation to be used is the Dated
Brent Assessment. For no. 6 fuel oil having 3% sulfur content, the Platt's
Price for any day is the average of the high and low spot prices for such fuel
oil as quoted for that day in Platt's Oilgram U.S. Marketscan (U.S. Gulf
Section, Waterborne Column).
The five-day period used to determine the price of Maya for any delivery is
(1) either the day on which the bill of lading is issued for such delivery if
the loading of tankers for such delivery begins within the three-day range for
the arrival of a tanker in the agreed lifting program for the relevant month,
or the middle day of such three-day range if the loading of tankers begins
after the last day of the three-day range plus (2) the two days before such
first day and the two days after such first day, other than Saturdays, Sundays
or other days when the relevant quotations do not regularly appear in the
Platt's publications referred to above.
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Alternative Pricing. If, during any six-month period when the regular price
is in effect, the average volume of sales of Maya at the regular price under
contracts with buyers not affiliated with P.M.I. Comercio Internacional,
including us, that may be terminated by the buyers on three months notice to
P.M.I. Comercio Internacional or less, is below 200,000 barrels per calendar
day, or if the average number of such non-affiliated buyers of Maya was less
than three per month, P.M.I. Comercio Internacional must notify us within 15
days following the end of that six-month period. Following this notice, the
parties are required to meet to discuss and agree on whether an alternative
pricing formula is needed and what the specifics of it should be. In deciding
upon an alternative pricing formula, the parties must apply a detailed
alternative pricing methodology. If the parties do not reach an agreement on an
alternative pricing mechanism within 60 days following the end of the six-month
period, they are required to submit the matter to arbitration.
Reinstatement of Regular Price. Following the establishment of an alternative
pricing mechanism, the price of Maya will return to the regular price if,
during any six-month period that ends after the initial six month period that
the alternative pricing mechanism is in effect, the average volume of sales of
Maya at the regular price under contracts with non-affiliated buyers that may
be terminated upon three months or less prior notice to P.M.I. Comercio
Internacional is equal to or greater than 200,000 barrels per calendar day, and
the average number of such non-affiliated buyers of Maya at the regular price
is equal to or greater than three per month.
Differential Formula and Guarantee
The regular price of Maya which we are required to pay is adjusted subject to
the gross margin support mechanism as described below.
Our gross margin support mechanism, which is referred to in this summary as
the "differential guarantee," is a $15 per barrel minimum average result of the
formula, described in this summary as the differential formula, designed to
serve as a proxy for coker gross margin.
Differential Formula
The "differential formula" is an amount in U.S. dollars per barrel calculated
according to the following formula:
. the average of the Platt's Prices for conventional 87 octane unleaded
gasoline for that month multiplied by 50%; plus
. the average of the Platt's Prices for 0.2% sulfur no. 2 fuel oil for that
month; minus
. one and a half times the average of the Platt's Prices for 3% sulfur no.
6 fuel oil for that month.
The term "Platt's Prices" for any day means (1) the low spot prices for
conventional 87 octane unleaded gasoline or 0.2% sulfur no. 2 fuel oil, as the
case may be, as quoted for that day in Platt's Oilgram Price Report (Spot Price
Assessments, U.S. Gulf Section, Pipeline Column) and converted to U.S. dollars
per barrel, and (2) in the case of no. 6 fuel oil, the low spot prices in U.S.
dollars per barrel for no. 6 fuel oil having 3% sulfur content as quoted for
such day in Platt's Oilgram U.S. Marketscan (U.S. Gulf Section, Waterborne
Column).
In the event that a regular quotation for a particular product or fuel oil
referred to above is suspended or interrupted for any reason in the relevant
publication for fewer than 10 of the days in any month, then the days for which
such quotation is suspended or interrupted are not taken into account in
calculating the average of the Platt's Prices for that product or fuel oil.
Moreover, that average is calculated for only the number of days in such month
that quotations were not suspended or interrupted. In the event that a regular
quotation for a particular product or fuel oil referred to above is suspended
or interrupted for any reason in the relevant publication for 10 or more days
in any month, then the parties are required to meet promptly to discuss and
agree upon an appropriate alternative reference price for calculation of the
differential.
Alternative Differential Calculation
In the event that (a) the absolute value of the arithmetic average, for the
immediately preceding 24 month period, of the difference between (1) the
regular price and (2) the sum of (A) 0.679 multiplied by the price of
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no. 6 fuel oil plus (B) 0.185 multiplied by the sum of the price of
conventional 87 octane unleaded gasoline and the price of 0.2% sulfur no. 2
fuel oil minus (C) 2.874, the "Maya proxy," exceeds (b) $0.50 per barrel for
any month, then the price of no. 6 fuel oil to be used in calculating the
Differential beginning in the month following that 24-month period will be
equal to the sum of (A) 1.473 multiplied by the regular price, plus (B) 4.233,
minus (C) 0.272 multiplied by the sum of the price of conventional 87 octane
unleaded gasoline and the price of 0.2% sulfur no. 2 fuel oil. Each of these
fuel oil and gasoline prices are to be determined according to the provisions
described above under "--Differential Formula and Guarantee."
Reinstatement of Differential Calculation
If an alternative differential calculation becomes applicable and thereafter
the absolute value of the arithmetic average, for the immediately preceding 24
month period, of the difference between the regular price and the Maya proxy is
equal to or less than $0.50 per barrel, then the price of no. 6 fuel oil to be
used in calculating the differential beginning in the month following such 24-
month period is as determined according to the formula used for calculating the
differential.
Determination of Surpluses and Shortfalls. A "monthly shortfall" for any
month all or part of which is within the guarantee period, is the amount equal
to the product of (1) $15.00 less the differential for that month, if greater
than zero, multiplied by (2) 36.6% of the monthly quantity of Maya delivered to
us by P.M.I. Comercio Internacional. If P.M.I. Comercio Internacional
underdelivers in any month, however, it will be deemed to have delivered us the
entire amount of Maya available in such month less any deliveries excused for
force majeure.
A "monthly surplus" for any month all or part of which is within the
guarantee period, is the amount equal to the product of (1) the differential
for that month less $15.00, if greater than zero, multiplied by (2) 36.6% of
the quantity delivered to us by P.M.I. Comercio Internacional in that month, as
prorated for any month which is only partly within the guarantee period. In the
event, however, that completion of the refinery upgrade project does not occur
by the guarantee date in July 2001, as such date may be extended by reason of
force majeure, for the purpose of determining any monthly surplus P.M.I.
Comercio Internacional will be deemed to have delivered the entire quantity of
Maya available for such month as if completion had been achieved. In addition,
in the event that we underlift Maya on or after the completion of the refinery
upgrade project then, for the purpose of determining any monthly surplus,
P.M.I. Comercio Internacional will be deemed to have delivered the entire
quantity of Maya available to us in such month less any volume that we have
been excused from underlifting pursuant the provisions described under "--
Remedies for Underlifting" above.
A "quarterly shortfall" with respect to any calendar quarter, is the amount,
if any, by which (1) the sum of the monthly shortfalls in such calendar quarter
exceeds (2) the sum of the monthly surpluses in such calendar quarter.
A "quarterly surplus" with respect to any calendar quarter, is the amount, if
any, by which (1) the sum of the monthly surpluses in such calendar quarter
exceeds (2) the sum of the monthly shortfalls in such calendar quarter.
Credit Interest. "Credit interest" with respect to any calendar quarter is
the amount of interest calculated for such calendar quarter (other than any
period during which processing at the Port Arthur refinery is curtailed due to
a force majeure event that extends the guarantee period) at LIBOR plus 1% on
the sum, if greater than zero, of:
. the aggregate of all credits calculated pursuant to the provisions
described under "--Shortfall in Differentials" below for all prior
calendar quarters; plus
. the aggregate amount of credit interest for all prior calendar quarters;
minus
. the aggregate of all premiums calculated pursuant to the provisions
described under "--Surplus in Differentials" below for all prior calendar
quarters.
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Shortfall in Differentials
If at the end of any calendar quarter, all or part of which is within the
guarantee period, there is a quarterly shortfall, we will receive a credit
against the purchase price of Maya delivered in the succeeding calendar
quarter. The credit will be equal to the sum, if greater than zero, of such
quarterly shortfall minus the amount, if any, by which the aggregate of all
quarterly surpluses for prior calendar quarters exceeds the aggregate of all
quarterly shortfalls and credit interest for prior calendar quarters. Formulas
for calculating these amounts are described above under "--Reinstatement of
Differential Calculation--Determination of Surpluses and Shortfalls" and "--
Credit Interest."
The sum of such credit plus any credit carryforward from such calendar
quarter minus any premium carryforward from such calendar quarter will be
applied at the rate of $5.00 per barrel of Maya beginning with the first barrel
delivered in such succeeding calendar quarter. The "premium carryforward" is
the amount that has not been applied to Maya delivered in such succeeding
calendar quarter by the end of the calendar quarter plus interest at LIBOR plus
1% calculated for the period of such succeeding calendar quarter. The maximum
credit to be applied in such succeeding calendar quarter is $30 million. If the
sum is less than zero, we must pay a premium on the purchase price of Maya
delivered in the succeeding calendar quarter. The premium is equal to the
positive value of such sum applied at the rate of $5.00 per barrel of Maya
beginning with the first barrel delivered in such succeeding calendar quarter.
The maximum premium to be applied in such succeeding calendar quarter is $20
million.
If, by the end of any such succeeding calendar quarter there remains an
amount which has not been applied as outlined in the preceding paragraph or in
provisions described below under "--Surplus in Differentials," to Maya
delivered in such succeeding calendar quarter, then such remaining amounts,
together with interest at LIBOR plus 1% calculated for the period of such
succeeding calendar quarter, will constitute a credit carryforward from such
succeeding calendar quarter.
If, by the end of any calendar quarter, all or part of which is within the
guarantee period, both the quarterly surplus and the quarterly shortfall equal
zero, and the sum of any credit carryforward minus any premium carryforward is
greater than zero, then we will receive a credit equal to such sum. The credit
is applied at the rate of $5.00 per barrel of Maya, beginning with the first
barrel of Maya delivered in such succeeding calendar quarter. The maximum
aggregate amount that may be applied is $30 million.
Surplus in Differentials
If, by the end of any calendar quarter, all or part of which is within the
guarantee period, the sum of monthly surpluses, exceeds the sum of monthly
shortfalls, there is a "quarterly surplus" in such calendar quarter and we are
required to pay a premium on the purchase price of Maya delivered beginning in
the succeeding calendar quarter. The amount of the premium equals the lesser of
(1) the amount of such quarterly surplus and (2) the amount that the aggregate
of all quarterly shortfalls and credit interest for prior calendar quarters and
such calendar quarter exceeds the aggregate of all quarterly surpluses for
prior calendar quarters.
The sum of (1) such premium, plus (2) any premium carryforward from such
calendar quarter minus (3) any credit carryforward from such calendar quarter
will be applied at the rate of $5.00 per barrel of Maya beginning with the
first barrel delivered in such succeeding calendar quarter. Such sum may be
applied up to a maximum aggregate amount in such succeeding calendar quarter of
$20 million. If the sum is less than zero, we will receive a credit against the
purchase price of Maya delivered in the succeeding calendar quarter. Such
credit will be equal to the positive value of such sum applied at the rate of
$5.00 per barrel of Maya beginning with the first barrel delivered in such
succeeding calendar quarter. The maximum credit that may be applied in such
succeeding calendar quarter is $30 million.
If, by the end of any calendar quarter, all or part of which is within the
guarantee period, both the quarterly surplus and the quarterly shortfall equal
zero, and the sum of any credit carryforward minus any premium carryforward is
less than zero, then we are required to pay a premium. The premium is equal to
the positive value of such sum, applied at the rate of $5.00 per barrel of
Maya, beginning with the first barrel of
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Maya delivered in such succeeding calendar quarter. The premium may be applied
to a maximum aggregate amount in such succeeding calendar quarter of $20
million.
End of Guarantee Period
The net adjustment amount, whether positive or negative existing at the end
of the period during which the coker gross margin support is available will be
applied over the remaining term of the agreement, after giving effect to the
operation of the differential mechanism in the last period. However, the
discount we receive in any quarter will not exceed $30 million and the premium
we pay in any quarter will not exceed $20 million.
Payment Terms
We are required to make all payments to P.M.I. Comercio Internacional when
due in immediately available U.S. dollars. Interest accrues daily on the amount
of any overdue payment, commencing on the date that the payment was due. The
rate per annum will be equal to 2% above the prime rate. We are required to
make all payments due P.M.I. Comercio Internacional punctually and without set-
off.
Security for Payment
Under specified circumstance, P.M.I. Comercio Internacional requires us to
provide security for the performance of our payment obligations by means of one
or more stand-by letters of credit or a financial guaranty insurance policy
meeting specified requirements. Such letters of credit or financial guaranty
insurance policy must always equal at least the total amount of all outstanding
invoices under the long term crude oil supply agreement plus 110% of the
estimated value of Maya that we have lifted but for which P.M.I. Comercio
Internacional has yet to issue an invoice. We will meet this obligation by
entering into the oil payment guaranty insurance policy with Winterthur.
Suspension of Deliveries
P.M.I. Comercio Internacional may suspend deliveries of Maya if we do not
make a payment of $100,000 or more that is due P.M.I. Comercio Internacional
under the long term crude oil supply agreement or any other crude oil agreement
between us. P.M.I. Comercio Internacional may also suspend deliveries if we do
not establish and maintain any stand-by letter of credit or financial guaranty
insurance policy that we are required to maintain. If P.M.I. Comercio
Internacional suspends deliveries and we subsequently make the required payment
together with accrued interest then P.M.I. Comercio Internacional is required
to resume deliveries but is not obligated to do so for a period of time equal
to the shorter of the suspension period or three months.
Termination
If we or P.M.I. Comercio Internacional default under our respective purchase
or sale obligations and such default continues for 60 days, the other party may
terminate the long term crude oil supply agreement effective immediately upon
notice.
Force Majeure--Purchase and Sale Related
General. Neither party is liable for any damages that arise from delays or
defaults in performance of the purchase and sale or delivery term provisions of
the long term crude oil supply agreement that are due to force majeure. If
either of us intends to rely on an event of force majeure to suspend our
performance, that party must give prompt notice of the event to the other
party. Force majeure will not relieve us of our obligation to pay for all Maya
delivered or any other amount that we owe to P.M.I. Comercio Internacional
under the long-term crude oil supply agreement.
Event of Force Majeure. Force majeure for these purposes includes any act or
event that prevents or delays either party from performing its obligations if
and to the extent that the act or event is beyond the party's control and is
not due to its fault or negligence, and to the extent that the party was not
able to overcome the consequence of by commercially reasonable efforts,
including spending funds.
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. acts of God or of the public enemy, floods, fire, electrical shortages or
blackouts;
. hostilities, war, blockades or riots;
. strikes or other labor disturbances that are not the result of breach of
a labor contract by the affected party;
. earthquakes, tides, storms or bad weather at the loading terminal;
. breakdown or injury to producing or delivering facilities in Mexico or to
receiving or processing facilities at the Port Arthur refinery;
. interruption, decline or shortage of P.M.I. Comercio Internacional's
supply of Maya available for export from Mexico, including shortage due
to increased domestic demand;
. laws, change in laws, decrees, regulations, orders or other directives or
actions of either general or particular application, other than as may be
directed to aspects of the long term crude oil supply agreement not
common to long term crude oil supply agreements generally, of the
government of Mexico or the government of the United States of America or
any agency thereof that does not include P.M.I. Comercio Internacional,
Pemex Exploracion y Produccion, or any of P.M.I. Comercio Internacional's
other affiliates; and
. ""governmental force majeure," which means the reduction of P.M.I.
Comercio Internacional's Maya deliveries under its contractual
commitments to export customers in general as a result of a direction
from the federal government of Mexico to curtail crude oil exports
despite the availability of Maya for export.
Apportionment. If P.M.I. Comercio Internacional does not have enough Maya
available to export for sale to us and its other customers because of force
majeure, it may not reduce the quantity of Maya that it sells to us by more
than the percentage that it reduces the total amount of its sales of Maya to
other export customers under agreements to supply 50,000 barrels per calendar
day or more of Maya or to its other customers in general if the agreements
account for less than 20% of its exports of Maya. P.M.I. Comercio Internacional
is not required to buy crude oil from another party to sell to us because of an
event of force majeure. If, however, the event is a governmental force majeure,
as described above, then the amount by which it would otherwise reduce the
quantity of Maya to be sold to us shall first be applied to reduce quantities
of Maya scheduled for sale and delivery to the Port Arthur refinery under any
other crude oil supply agreement with us or any of our affiliates.
The Refinery Upgrade Project
Obligation to Complete the Refinery Upgrade Project
Under the long term crude oil supply agreement, we are obligated to complete
the refinery upgrade project by the scheduled completion date of January 2001.
If, however, the refinery upgrade project is not complete by such scheduled
completion date, we may make payments to P.M.I. Comercio Internacional to
extend the scheduled completion date according to a specified formula. We
expect such payments to equal approximately $400,000 per month for each of the
first six months we choose to extend the scheduled completion date and
approximately $200,000 per month for each month beyond six months that we
choose to extend the scheduled completion date. Such date is subject to
extension for specified events of force majeure or other events beyond our
reasonable control in the same manner as extension of the guarantee date up to
a total of 365 days.
For purposes of the long term crude oil supply agreement and this summary of
such agreement, completion of the refinery upgrade project occurs when:
. all significant aspects of the refinery upgrade project are mechanically
complete and substantially conform to their design plans and
specifications;
. the commission testing of processing units in the refinery upgrade
project is complete; and
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. the Port Arthur refinery and the new delayed coking unit are able to
process at least 80% of their design capacities on average over a 30 day
consecutive period, or, we commence operation of the new delayed coking
unit and other equipment integrated into the Port Arthur refinery that we
own and we and Foster Wheeler USA stop making efforts to achieve those
average processing capacities.
If we fail to extend the scheduled completion date, P.M.I. Comercio
Internacional has the right to terminate the long term crude oil supply
agreement. In such case, we are liable to P.M.I. Comercio Internacional for
their resulting damages, subject to our termination rights described in the
following paragraph and the limitations on liability described below.
Our Right to Terminate the Long Term Crude Oil Supply Agreement
Prior to the first day of the month in which we expect to first introduce
feed into our new delayed coking unit, we may terminate the long term crude oil
supply agreement under the following circumstances:
. If we abandon the refinery upgrade project or decide to continue the
refinery upgrade project without the benefit of the long term crude oil
supply agreement or an alternative supply arrangement, we may terminate
the long term crude oil supply agreement by first giving notice to P.M.I.
Comercio Internacional and within fifteen days paying them a termination
payment. For the purposes of the long-term crude oil supply agreement an
alternative supply arrangement means any contract, agreement or
arrangement, other than the long term crude oil supply agreement,
pursuant to which we, any purchaser of the Port Arthur refinery or any
part thereof, or any affiliate of any of us has the right to purchase, on
a long term basis, any substantial portion of the Port Arthur refinery's
requirements for heavy sour crude oil attributable to the refinery
upgrade project or to any similar upgrade project designed to increase
significantly the Port Arthur refinery's capacity to process heavy sour
crude oil having characteristics similar to Maya; and
. We may also terminate the long term crude oil supply agreement without
abandoning the refinery upgrade project by entering into an alternative
supply arrangement and paying P.M.I. Comercio Internacional the
termination payment described above plus an additional fee equal to their
damages resulting from a breach of the long term crude oil supply
agreement in its entirety.
Limitation of Liability
Neither party is liable for any consequential or punitive damages of any kind
arising out of or in any way connected with the performance, of or failure to
perform, the long term crude oil supply agreement including, but not limited
to, losses or damages resulting from shutdown of plants or inability to perform
sales or any other contracts arising out of or in connection with the
performance or nonperformance of the long term crude oil supply agreement. This
liability limitation is not meant to limit either party's right to recover its
incidental damages or damages associated with the mechanism for adjustment to
our payment obligations described under "--Differential Formula and Guarantee"
above.
Miscellaneous Provisions
Dispute Resolution
If a dispute arises from the long term crude oil supply agreement, the
parties are to seek to settle the dispute through good faith negotiation
between senior executives. If after 60 days the dispute is not settled, either
party may initiate arbitration of the dispute. All disputes arising from the
long term crude oil supply agreement will be settled finally by arbitration
under the Rules of Arbitration and Conciliation of the International Chamber of
Commerce. The arbitration will occur in New York, in English and the
substantive law will be that of the State of New York.
Governing Law
The long term crude oil supply agreement is governed by and interpreted in
accordance with the laws of the State of New York. The United Nations
Convention on the International Sale of Goods will not apply to the long term
crude oil supply agreement.
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Language
English is the language of the long term crude oil supply agreement and
controls over any Spanish language translations.
Entire Agreement
The long term crude oil supply agreement supersedes all prior agreements
between us and our affiliates and P.M.I. Comercio Internacional and its
affiliates except the crude oil sales agreement entered into on January 1,
1990, between P.M.I. Comercio Internacional and Clark Oil & Refining
Corporation, the predecessor company to Clark Refining & Marketing, as amended
and assigned and which remains in force.
Construction Contract
We entered into a contract for engineering, procurement and construction
services with Foster Wheeler USA in July 1999. This construction contract
obligates Foster Wheeler USA to engineer, design, construct, erect, install and
test our coker project, to provide procurement services and training support
for us and to oversee start-up, operation and performance testing of our coker
project.
Effective Date and Commencement of Work
Foster Wheeler USA did not commence work under the construction contract and
we had no obligation with respect to the construction contract until August
1999 when:
. all other documents related to our coker project had been executed and
delivered by all parties;
. the initial issuance of outstanding notes had occurred and we had
sufficient funds available to acquire the work in progress related to our
coker project from Clark Refining & Marketing; and
. we delivered a notice to proceed to Foster Wheeler USA.
Contractor's Responsibilities
Scope of Work
The responsibilities of Foster Wheeler USA under the construction contract
include, among other things:
. providing all engineering and design services necessary for the
completion of our coker project;
. procuring all labor, materials, equipment, supplies and other services
necessary for completion of our coker project except supplies to be
provided by us;
. providing all construction, erection and installation services necessary
for the completion of our coker project except services to be provided by
us;
. obtaining all permits necessary for the construction, except permits
provided by us;
. performing all cleanup, removal and disposition services with respect to
hazardous waste and other debris resulting from its work at the
construction site;
. initiating, maintaining and supervising all safety precautions and
programs in connection with performance of the construction contract;
. cooperating with, and overseeing, our start-up of our new processing
units and the operation of our new processing units during start-up and
performance testing;
. carrying out all tests and inspections required under the construction
contract;
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. preparing initial operational guidelines for our new processing units,
cooperating with us in preparation of initial drafts of operation manuals
for our units and ensuring the proper content of final operating manuals;
. providing maintenance and instruction manuals and mechanical catalogs for
our new processing units;
. providing lists of recommended spare parts for our new processing units
and cooperating with us and Purvin & Gertz in its role as independent
engineer to ensure procurement of spare parts; and
. fulfilling Purvin & Gertz's requests for information.
Subcontracting
Foster Wheeler USA may not subcontract any portion of the work to be
performed under the construction contract without our consent. Foster Wheeler
USA will remain responsible for all its obligations under the construction
contract regardless of its reliance on subcontractors. Foster Wheeler USA will
ensure that major subcontract agreements provide that, in the event Foster
Wheeler USA is terminated as contractor, (1) the subcontractor will continue
performance if requested by us and (2) the subcontract may be assigned to us or
to the holders of our senior debt for security on the same terms as the
original agreement.
Assumption of Risk
Prior to execution of the construction contract, Foster Wheeler USA was
performing portions of the work at the construction site pursuant to an interim
reimbursable contract with Clark Refining & Marketing. Foster Wheeler USA has
acknowledged, among other things, that it has examined the construction site
and made independent inquiries into the availability of materials, labor and
other supplies and is satisfied that each is sufficient for performance of its
obligations. Foster Wheeler USA has also acknowledged that we and Clark
Refining & Marketing have provided them other information with respect to
existing subsurface conditions and facilities at the construction site and has
agreed that the construction site is satisfactory for performance of the
construction contract. Accordingly, Foster Wheeler USA has assumed price and
schedule risks associated with construction site conditions, except risks
associated with hazardous waste existing at the construction site on the
execution date of the construction contract other than hazardous waste that is
known to us that we have disclosed to Foster Wheeler USA.
Contract Amount and Payment
Fixed Price
As full compensation for performance of its obligations under the
construction contract, we will pay Foster Wheeler USA a fixed price of $544
million. The fixed price is subject to change based on valid change orders, as
described below under "--Changes in Work." This price includes work performed
under Clark Refining & Marketing's existing reimbursable contract with Foster
Wheeler USA through the effective date of the construction contract.
Approximately $157.1 million paid under such contract through July 1999 and
related to our coker project has been credited against our fixed contract
price. We are required to make payments to Foster Wheeler USA in monthly
installments based on receipt and approval of invoices from Foster Wheeler USA
and the achievement of specified construction milestones.
Letters of Credit or other Payment Security
As security for its performance under the construction contract, Foster
Wheeler USA has provided us with a letter of credit on the effective date of
the construction contract. Foster Wheeler USA is obligated to maintain one or
more letters of credit with an aggregate amount available for drawings always
equal to at least 10% of amounts actually paid by us to Foster Wheeler USA less
the amount of all prior drawings other than drawings made when the rating of
the issuer of the letter of credit has fallen below the required rating or
final completion
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has not occurred 30 days prior to the expiration of such letter of credit and
it has not been extended or substituted. Foster Wheeler USA has the option to
fulfill its letter of credit obligations, in whole or in part, by either
depositing cash with us pursuant to a cash collateral agreement acceptable to
us or our senior debt holders or by requesting that we withhold amounts that
would otherwise be payable to them under the construction contract.
The issuer of such letter of credit must meet specified standards including,
among others, that it have outstanding unsecured debt rated A or better by
Standard & Poor's or A2 or better by Moody's.
Our Responsibilities
Our responsibilities under the construction contract include, among other
things:
. paying installments of the fixed contract amount upon achievement of
construction milestones;
. providing limited construction services;
. providing water and temporary utilities necessary for Foster Wheeler
USA's performance of the construction contract and providing other
consumables; and
. operating our new processing units and other equipment during start-up
and testing, including supply of necessary feedstreams and disposition of
output, subject to Foster Wheeler USA's right to exercise such
supervision and control as necessary for its performance of the
construction contract.
Independent Engineer
The construction contract entitles the holders of our senior debt to retain
an independent engineer, Purvin & Gertz, who will, among other things:
. review and report on Foster Wheeler USA's monthly status reports;
. review and monitor the performance tests and other tests and inspections
performed by Foster Wheeler USA;
. review and approve applications by Foster Wheeler USA for installment
payments of the contract amount;
. inspect Foster Wheeler USA's performance and any labor, materials and
equipment furnished or used by Foster Wheeler USA;
. approve use by Foster Wheeler USA of non-prototype equipment or
subcontractors not on the pre-approved list of subcontractors; and
. approve achievement of mechanical completion and final completion, each
as described below.
Mechanical Completion and Other Conditions to Performance Testing
Mechanical Completion
Foster Wheeler USA is obligated to achieve mechanical completion of our
coker project before commencement of commissioning and start-up of our new
processing units by March 2001, as such date may be extended pursuant to valid
change orders.
Mechanical completion of our coker project will occur when the following
have been achieved:
. each physically discrete unit of our coker project has been erected and
has passed specified tests;
. Foster Wheeler USA has completed all work under the construction contract
except for minor items and inconsequential defects and deficiencies,
which will be considered punch list items;
. we, Foster Wheeler USA and Purvin & Gertz have agreed to a punch list and
a start-up protocol;
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. our coker project can operate safely and meets all requirements of the
construction specifications necessary to begin commissioning and start-up
activities;
. we and Purvin & Gertz have approved a notice of mechanical completion
delivered by Foster Wheeler USA; and
. we have received final operating manuals and maintenance and instruction
manuals from Foster Wheeler USA.
The actual date of mechanical completion will be deemed to occur on one of
the following dates:
. on the date when all requirements for mechanical completion, as described
above, have been achieved;
. on the date when all requirements for mechanical completion are met
except for mechanical completion of our new delayed coking unit, provided
that it is mechanically complete within 14 days of the achievement of all
other conditions to mechanical completion; or
. on the date that is 14 days prior to the date that mechanical completion
of our new delayed coking unit is achieved if mechanical completion of
our new coking unit is achieved more than 14 days after the date that all
other conditions to mechanical completion are achieved.
Commissioning and Start-Up
Once our coker project is mechanically complete, we, with the cooperation of
Foster Wheeler USA and Purvin & Gertz, will conduct test runs and other start-
up activities for our coker project. Foster Wheeler USA will oversee these
commissioning activities and monitor them to determine whether these activities
are conducted in conformance with the construction contract and the start-up
protocol developed by the parties. Foster Wheeler USA must give us immediate
notice if any commissioning or start-up activities are not conducted in
accordance with such standards. Accordingly, Foster Wheeler USA will not have a
defense to its liabilities under the construction contract based on our use of
improper procedures or other occurrences during this period unless it gives us
such notice.
Performance Testing and Guarantees
Following mechanical completion of our coker project, Foster Wheeler USA is
responsible for conducting performance tests to:
. demonstrate achievement of the performance guarantees of Foster Wheeler
USA;
. demonstrate achievement of final completion of our coker project; and
. determine damages for failure to achieve such performance and completion
guarantees.
Guaranteed Reliability
Foster Wheeler USA will conduct a reliability test to demonstrate whether
during a continuous 60-day period our new processing units achieve 100% of a
specified guaranteed "daily net margin" while not exceeding the guaranteed
emissions and effluent limits described below. The calculation of the daily net
margin is based on a specified price set for valuing feedstocks processed
during reliability testing, the variable costs of processing such feedstocks
and the products produced by our new units during such testing and is intended
to serve as a proxy to demonstrate whether our new processing units can
reliably generate expected operating margins.
Substantial Reliability
If a reliability test demonstrates that our new processing units have
achieved 95% of the specified guaranteed daily net margin, Foster Wheeler USA
will be deemed to have achieved substantial reliability.
Guaranteed Capacity
Foster Wheeler USA will also conduct a capacity test to demonstrate whether
for a continuous uninterrupted 72 hour period each of our new processing units
achieves specified guaranteed design capacities while not exceeding the
guaranteed emissions and effluent limits.
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Guaranteed Emissions and Effluent Limits
For either a capacity or reliability test to be successful, Foster Wheeler
USA must also demonstrate during such test that operation of our new processing
units will meet specified guaranteed standards for emission of gaseous, liquid
and solid pollutants which are designed to ensure compliance with our air
emissions permit.
Final Completion
Foster Wheeler USA is obligated to achieve "final completion" of our coker
project by December 2001, as such date may be extended pursuant to valid change
orders. Final completion of our coker project will occur when, among other
things:
. mechanical completion has been achieved;
. either (1) a reliability test has demonstrated that 100% of the
guaranteed reliability has been achieved and the guaranteed capacities
described above have been achieved or (2) Foster Wheeler USA has
successfully concluded a reliability test demonstrating achievement of
substantial reliability as described above and has paid us the applicable
amounts described below under "--Buydown Payments for Failure to Achieve
Guaranteed Reliability or Capacity";
. Foster Wheeler USA has paid us any late payments that are due to us as
described below under
"--Damages for Delay";
. all punch list items have been completed or the completion of such items
has been temporarily waived by us, with the approval of Purvin & Gertz;
and
. we and Purvin & Gertz have issued a certificate approving Foster Wheeler
USA's notice of final completion.
Damages for Delay
Delay in Achieving Mechanical Completion
If Foster Wheeler USA fails to achieve mechanical completion by January 2001,
as such date may be extended pursuant to valid change orders, they are
obligated to pay us late payments for each day from such date until December
2001, as such date may also be extended pursuant to valid change orders.
Delay in Achieving Guaranteed Reliability
Without duplication of late payments for delay in achieving mechanical
completion, Foster Wheeler USA is also obligated to pay us late payments for
each day after January 2001, as such date may be extended pursuant to valid
change orders, that it fails to demonstrate achievement of 100% of the
guaranteed daily net margin.
Amount of Late Payments
Late payments will be calculated on a daily basis. Late payments due each day
will equal one-seventh of the applicable cost factor in the following chart.
After July 2001 late payments will also include a "throughput factor" intended
to replace the loss of expected profits.
<TABLE>
<CAPTION>
Date Cost Factor
---- -----------
<S> <C>
January 1, 2001 -- January 31, 2001.............................. $ 100,000
February 1, 2001 -- March 31, 2001............................... $1,146,250
April 1, 2001 -- June 30, 2001................................... $1,842,500
July 1, 2001 -- September 30, 2001............................... $1,595,000
October 1, 2001 forward.......................................... $2,750,000
</TABLE>
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The throughput factor will be calculated on a daily basis according to the
following formula:
$12.00 * (76,300 less the number of barrels of throughput processed by our
new coker on that day)
76,300 barrels per day is approximately 95% of the design capacity of our new
coking unit.
Operating Revenue Credit Against Late Payments
For each day that Foster Wheeler USA makes late payments to us, we will
provide them a credit against future late payments equal to our operating
revenue for such day. For this purpose our operating revenue is defined as the
difference between our cash revenues and cash expenses attributable to such
day.
Early Completion Bonus
For each day that Foster Wheeler USA achieves mechanical completion prior to
the target date of November 2000 or 60 days prior to guaranteed mechanical
completion, whichever is later, they will receive a bonus payment equal to one-
seventh of $900,000 for each such day during September 2000 and one-seventh of
$600,000 for each such day during October 2000. The total amount of all such
bonuses, however, may not exceed $6 million. In no event will Foster Wheeler
USA receive such bonus payments if it (1) incurs an obligation to make late
payments or payments for failure to achieve its guarantees of capacity or
reliability or (2) fails to achieve final completion of our coker project.
Buydown Payments for Failure to Achieve Guaranteed Reliability or Capacity
If Foster Wheeler USA fails to achieve 100% of the guaranteed daily net
margin described above, it will be obligated to make buydown payments according
to a specified formula.
If Foster Wheeler USA fails to achieve 100% of the guaranteed design
capacities it will be obligated to make additional buydown payments to us
according to specified formulas up to a maximum amount of $2 million related to
our new coking unit and up to $5 million related to our new hydrocracker.
Limitations on Liability
Late Payments
Foster Wheeler USA's liability for failing to achieve mechanical completion
by January 2001, as such date may be extended by valid change orders, or
failure to achieve the guaranteed daily net margin by such date is limited to
making the late payments described above. In addition, if Foster Wheeler USA
demonstrates achievement of substantial reliability during a reliability test,
its liability for making late payments to us will be capped at $70 million.
Buydown Payments
Foster Wheeler USA's liability for failing to achieve the guaranteed daily
net margin, the guaranteed standards of emissions and effluent limits or the
guaranteed capacities is limited to making the payments described above under
"Buydown Payments for Failure to Achieve Guaranteed Reliability or Capacity."
In addition, if Foster Wheeler USA demonstrates achievement of substantial
reliability during a reliability test, its liability for making such payments
to us will be capped at $75 million.
Total Damages
Foster Wheeler USA's total liability for damages arising under the
construction contract is capped at 100% of our fixed contract amount. This
liability cap, however, does not apply to any damages arising out of Foster
Wheeler USA's indemnification obligations.
Integration of Other Portions of the Refinery Upgrade Project
Work by Foster Wheeler USA. Foster Wheeler USA bears the risk of successfully
integrating our new units with the remainder of the Port Arthur refinery to the
extent that the refinery is modified or improved
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by the work to be performed by Foster Wheeler USA under its reimbursable
contract with Clark Refining & Marketing. In the event of any defect or
deficiency in such work, the obligation to correct defects or deficiencies is
the responsibility of Foster Wheeler USA and Clark Refining & Marketing.
Work by Us or Clark Refining & Marketing. We and Clark Refining & Marketing
bear the risk of successfully integrating our new units with the remainder of
the Port Arthur refinery to the extent in each case that work on units,
equipment items or systems is performed by Clark Refining & Marketing or us, as
the case may be.
Overall Schedule. Foster Wheeler USA must identify and notify us of the
overall schedule of work to be performed by it under its reimbursable contract
with Clark Refining & Marketing and the work required to be performed by Clark
Refining & Marketing as is required for the integration of our new processing
units with the remainder of the Port Arthur Refinery.
Limitation on Foster Wheeler USA's Defenses. The failure of Foster Wheeler
USA to perform under its reimbursable contract with Clark Refining & Marketing
will not provide a defense to or excuse Foster Wheeler USA from making late
payments or buydown payments in the event it fails to achieve mechanical
completion, final completion or meet its capacity, reliability and emissions
and effluent limit guarantees if:
. Foster Wheeler USA performs the work under the reimbursable contract
with Clark Refining & Marketing with our consent; and
. Clark Refining & Marketing completes its portion of the refinery upgrade
project in a timely fashion and in accordance with the schedule provided
to us by Foster Wheeler USA.
Warranty Provisions
Warranties
Foster Wheeler USA warrants and guarantees to us, among other things, that
(1) all equipment, materials and other items furnished by them will be new and
meet a generally accepted standard of quality applicable to the design and
engineering of oil refinery installations of similar size, type and design to
the Port Arthur refinery, free from improper workmanship and defects and
deficiencies and in conformity with the construction contract, applicable law,
permits and manufacturer's specifications and warranty requirements and (2)
when complete, our coker project shall be free of all defects and deficiencies
caused by errors and omissions in engineering and design or otherwise.
Warranty Periods
Foster Wheeler USA's obligations and liabilities with respect to its
warranties under the construction contract extend for the following periods:
<TABLE>
<CAPTION>
Nature of Defect or Deficiency Period of Warranty
------------------------------ ------------------
<S> <C>
Engineering and design errors and omissions and One year after final
defects and deficiencies in the structure and completion
foundations of our coker project
A defect or deficiency arising or first The earlier of (1) one year
existing in from discovery and (2) two
the year following final completion and which years after final completion
would not have been revealed by a reasonable
inspection at the end of such year
All others One year after final
completion
</TABLE>
If any machinery, equipment, materials or supplies are replaced during any
warranty period, then the warranty period for such machinery, equipment,
materials or supplies will be extended for one year after
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replacement. Similarly, if any errors, omissions or resulting defects and
deficiencies in engineering design or otherwise are corrected during the last
year of a warranty period, the warranty for the corrected work will be extended
for one year after correction.
Warranty Obligations
During any warranty period Foster Wheeler USA, at its own expense and without
any additional compensation, is obligated to (1) correct promptly any warranted
work performed that is defective or not in conformance with applicable
standards and (2) correct any defects and deficiencies caused by errors and
omissions in engineering and design or otherwise as soon as reasonably possible
after receipt of notice from us specifying such defects and deficiencies.
Subcontractor Warranties
Foster Wheeler USA must obtain guarantees and warranties from subcontractors
on all machinery, equipment, services, materials, supplies and other items used
and installed in connection with the construction contract. Such guarantees and
warranties are to extend for a period of no less than twelve months from start-
up or eighteen months after delivery, whichever occurs first. Upon expiration
of its warranties or termination of the construction contract, Foster Wheeler
USA is obligated to assign all Foster Wheeler USA's rights under subcontractor
warranties to us.
Indemnities
Foster Wheeler USA will indemnify us for damages relating to:
. any personal injury or property damage arising before mechanical
completion and in any way connected with the performance of the work
without regard to whether our negligence or fault is a concurrent or
contributory cause of such damage;
. any breach of representation, warranty or covenant of Foster Wheeler USA;
. any failure by Foster Wheeler USA to comply with any law or governmental
regulation which causes damages to arise before mechanical completion;
. any claimed or actual infringement of intellectual property rights
arising in connection with Foster Wheeler USA's performance of the
construction contract prior to mechanical completion;
. any liabilities arising from hazardous waste brought or created on our
coker project site after commencement its work at the site; and
. any liens, claims and demands which arise in connection with work or
materials performed or supplied by Foster Wheeler USA.
We will indemnify Foster Wheeler USA for any liabilities arising from
hazardous waste located at the coker project site on or prior to Foster Wheeler
USA's commencement of work at the site or brought or created on the site after
such commencement.
We and Foster Wheeler USA will indemnify each other party against any damages
relating to:
. any personal injury or property damage arising after mechanical
completion and in any way connected with the performance of the
construction contract; and
. any failure of the party to comply with any law or governmental
regulation which causes the damages to arise after mechanical completion.
Insurance and Risk of Loss
Risk of physical loss to the items of work performed by Foster Wheeler USA
under the construction contract remains with Foster Wheeler USA until final
completion is achieved. Until such time, Foster Wheeler
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USA is responsible for obtaining and maintaining the following insurance
coverage for our coker project in compliance with the more detailed
requirements of the construction contract:
. workers compensation;
. automobile insurance;
. commercial general liability;
. excess liability insurance;
. marine cargo insurance, including coverage for consequential loss;
. all builders risk insurance;
. delay in start-up insurance; and
. pollution liability coverage for itself and its subcontractors.
Foster Wheeler USA is also responsible for causing subcontractors who are
engaged after the effective date of the construction contract to maintain
insurance including, as applicable, workers compensation, automobile,
equipment, marine, aircraft liability, commercial general liability and excess
liability insurance coverages.
Excuse for Force Majeure or Delay Caused by Us
Force Majeure
Foster Wheeler USA or we may make a claim for excusable delay or failure to
perform under the construction contract if any of the following events of force
majeure occur, which events are beyond the reasonable control of the party
making such claim and such party has given the other party ten days notice of
its knowledge of such event:
. acts of God, natural disasters or other extraordinary weather conditions;
. acts of war, blockade, insurrection, riot, civil disturbance or similar
occurrences or any exercise of the power of eminent domain or other
similar taking by a public or private entity;
. acts of governmental authorities, changes in law or a failure of the
effectiveness of any necessary permit;
. strikes, boycotts or lockouts, except those involving the employees of
Foster Wheeler USA and which are not national or industry-wide;
. a partial or entire delay or failure of utilities; and
. failure of a subcontractor to furnish services or materials when caused
by any of the above events of force majeure.
Delay Caused by Us
Foster Wheeler USA may also make a claim for relief if any of the following
delays occur:
. we suspend Foster Wheeler USA's performance as described below under "--
Termination for Our Convenience and Right to Suspend Work";
. a change in any of the documents related to our coker project or our
senior debt obligations that materially and adversely affects Foster
Wheeler USA; or
. a failure by us or Purvin & Gertz to perform our respective obligations
under the construction contract, unless such failure is due to Foster
Wheeler USA's fault, negligence or failure to perform.
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Additional Relief
Should an event of force majeure or delay caused by us occur, relief may
also be provided in the form of a change order. Such change order may provide
for:
. an increase in the fixed contract amount;
. an extension of the dates on which Foster Wheeler USA is required to pay
damages or demonstrate achievement of mechanical completion, substantial
reliability or final completion; or
. a change in the value of Foster Wheeler USA's guarantees of design
capacities, reliability or emissions and effluent limits.
Limitation on Relief and Delay
Any claim by Foster Wheeler USA for any extension of time will not be given
unless the event of force majeure or delay that we caused adversely affects
Foster Wheeler USA's critical path to completion of our coker project. Any
excuse for performance will be of no greater scope and no longer duration than
is reasonably required. The non-performing party is obligated to use
reasonable efforts to mitigate or limit damages to the other party.
An event of force majeure will not excuse Foster Wheeler USA from achieving
final completion by the date that is 180 days after the guaranteed final
completion date of December 2001, as such date may be extended by valid change
orders. No single event of force majeure will excuse Foster Wheeler USA for
delays exceeding 90 days.
Changes in Work
We or Foster Wheeler USA may request additions, deletions or revisions to
Foster Wheeler USA's responsibilities under the construction contract pursuant
to valid change orders that conform to the provisions of the construction
contract. We have broad discretion to make any change in Foster Wheeler USA's
work under the construction contract by designating a change order at any
time. If we initiate a change order, we may also request Foster Wheeler USA to
make a proposal for completing the requested change. Foster Wheeler USA may
not request change orders that adversely affect completion of our coker
project or, to our detriment, change the fixed contract amount, the
construction or payment schedule or any of Foster Wheeler USA's performance or
completion guarantees. We have complete discretion to approve or reject any
change order requested by Foster Wheeler USA. Purvin & Gertz must approve any
change order in excess of $0.5 million and change orders, in the aggregate, in
excess of $5 million. You should note that the common security agreement
contains additional limitations on our ability to approve change orders.
Title and Risk of Loss
Title to all drawings, specifications and other technical documents related
to our coker project and produced by Foster Wheeler USA and its subcontractors
and all work, materials and equipment performed or supplied under the
construction contract passes to us when payment is made for such items. The
risk of physical loss of such items, however, remains with Foster Wheeler USA
until final completion is achieved.
Our Right to Terminate and Other Remedies
Right to Terminate Construction Contract
We have the right to terminate the construction contract or draw on the
letter of credit described above under "--Contract Amount and Payment--Letters
of Credit or other Payment Security" subject to specified notice requirements
and cure periods, in specified cases, including if:
. Foster Wheeler USA or Foster Wheeler Corporation becomes insolvent or
bankrupt;
. Foster Wheeler USA fails to make payments to subcontractors;
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. Foster Wheeler USA persistently or materially disregards or violates
applicable laws or permits;
. Foster Wheeler USA fails to perform in accordance with the terms of the
construction contract;
. Foster Wheeler USA abandons or ceases for a period in excess of 30 days
its performance of the construction contract;
. Foster Wheeler USA fails to perform the construction contract in any way
that prejudices the financing of the our coker project;
. Foster Wheeler USA fails to achieve substantial reliability by September
2001, as such date may be extended pursuant to valid changes orders, or
by such later date as agreed to by Purvin & Gertz and the holders of our
senior debt;
. Foster Wheeler USA fails to pay to us any amount due by the date required
for such payment;
. Foster Wheeler USA fails to extend, renew or replace the letter of credit
described above when and as required;
. Foster Wheeler USA otherwise breaches any material provision of the
construction contract;
. the guarantee provided by Foster Wheeler Corporation is no longer in full
force or effect;
. Foster Wheeler USA fails to achieve mechanical completion by March 2001,
as such date may be extended by valid change orders or extended for up to
60 days provided certain conditions are fulfilled, including compliance
with the requirements of our common security agreement; or
. Foster Wheeler USA fails to achieve final completion by December 2001, as
such date may be extended by valid change orders.
Right to Take Over Work
If we choose to terminate the construction contract as provided above, we
also have the right to take over and finish performance of Foster Wheeler USA's
work under the construction contract.
Termination for Our Convenience and Right to Suspend Work
We may terminate the construction contract for our convenience at any time
upon written notice to Foster Wheeler USA. In such case, we will be obligated
to pay:
. Foster Wheeler USA's actual costs reasonably incurred in connection with
performance of the construction contract as of the date of termination;
. any other costs actually and directly incurred by Foster Wheeler USA in
demobilizing, canceling subcontracts or withdrawing from our coker
project site; and
. the amount of any improper or excessive drawings under the letter of
credit described above.
We also have the right to order Foster Wheeler USA to suspend all or part of
its performance of the construction contract for such period of time as we
desire. In such case, Foster Wheeler USA may make a claim for a change order,
but no such change order will be granted if its performance was or would have
been suspended due to its own fault or if the suspension had no effect on
Foster Wheeler USA's critical path to completion.
Contractor's Right to Terminate
If we are in default in making any payment due Foster Wheeler USA, Foster
Wheeler USA may, on 90 days notice to us and the holders of our senior debt,
terminate the construction contract upon our senior debt holders' failure to
cure such default. In addition, on 30 days notice, Foster Wheeler USA may
suspend its performance until the payment default is cured.
If Foster Wheeler USA terminates the construction contract, its exclusive
remedy is payment of the costs described above under "--Termination for Our
Convenience and Right to Suspend Work." In such case, we have the option to
take over Foster Wheeler USA's performance as described above under "--Our
Right to Terminate and Other Remedies--Right to Take Over Work."
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Governing Law and Dispute Resolution
The construction contract is governed by the laws of the State of New York,
except with respect to mechanic's liens, which are governed by the laws of the
State of Texas.
The construction contract provides a procedure for amicable resolution of
disputes between Foster Wheeler USA and us, including claims of force majeure
and delay caused by us. If such procedure is unsuccessful, the construction
contract provides that claims involving less than $3 million will be decided by
the Construction Industry Arbitration Rules of the American Arbitration
Association and claims exceeding $3 million will be resolved in the Supreme
Court of New York or the Federal District Court for the Southern District of
New York.
Assignment of Construction Contract
We may assign our interest and obligations under the construction contract to
the holders of our senior debt without Foster Wheeler USA's consent. Foster
Wheeler USA may not assign any portion of the construction contract without our
prior written consent.
Services and Supply Agreement
We and Clark Refining & Marketing entered into a services and supply
agreement in August 1999, simultaneously with the issuance of the outstanding
notes. Under the services and supply agreement Clark Refining & Marketing is
obligated to provide us a number of services and supplies needed for completion
of our coker project and operation of our heavy oil processing facility.
Subject to the early termination rights of each party described below, this
services and supply agreement will extend for a term of 30 years.
Obligations of Clark Refining & Marketing
Except to the extent that our employees are to operate our new processing
units and to the extent that we have entered into third party contracts for the
supply of crude oil and hydrogen, Clark Refining & Marketing is obligated to
operate, manage and maintain all components of our heavy oil processing
facility and provide all necessary feedstocks and other materials in order to
generate the quantity and quality specifications of products required under our
product purchase agreement with them. Clark Refining & Marketing is to provide
such services and supplies in a prudent and efficient manner in compliance
with:
. applicable laws and permits;
. prudent industry practice;
. requirements of applicable warranties and equipment manufacturers'
recommended maintenance procedures;
. the operating manuals, the maintenance and instruction and the mechanical
catalogs to be prepared pursuant to our construction contract;
. all other principal project documents; and
. all documents related to the financing of our senior debt, including the
notes.
Construction Management
Clark Refining & Marketing is managing the construction of our coker project
and must cooperate with Purvin & Gertz, in its role as independent engineer, to
ensure the construction of our coker project in accordance with our
construction contract with Foster Wheeler USA. In this regard, Clark Refining &
Marketing is obligated to fulfill all our obligations, and perform all our
functions under the construction contract, other than our payment obligations.
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Crude Oil Supply Management
Clark Refining & Marketing will manage our crude oil purchases and the
delivery of our crude oil to the Port Arthur refinery. In this regard, Clark
Refining & Marketing is responsible for:
. coordinating the scheduling and execution of deliveries of our crude oil
to our heavy oil processing facility;
. supplying us with any additional crude oil required for start-up and
operation of our heavy oil processing facility prior to final completion
of our coker project;
. procuring contract(s) on our behalf for the supply of the light sour
crude oil needed for processing our heavy sour crude oil;
. procuring alternative supplies of other crude oil or feedstocks on our
behalf if the full supply of Maya under our long term crude oil supply
agreement becomes unavailable for any reason;
. hiring tankers on our behalf and at our expense to ship our crude oil to
the Port Arthur refinery and ensuring that before arrival, our crude oil
will not be mixed with any of Clark Refining & Marketing's crude oil in
such shipments; and
. providing all necessary docking, pipeline, handling and storage services
with respect to our crude oil or other feedstocks delivered to our heavy
oil processing facility.
To the extent that crude oil owned by Clark Refining & Marketing is
delivered to the Port Arthur refinery by the same pipeline as our crude oil,
title to the mixed oil will be allocated according to the respective volume of
crude oil that we and Clark Refining & Marketing each purchase. In addition,
Clark Refining & Marketing has agreed not to grant any liens on crude oil that
it owns that is mixed with our crude oil at the Port Arthur refinery, other
than the granting of purchase money security interests needed to secure
purchases of their crude oil.
Operation and Maintenance
Leased Facilities. Clark Refining & Marketing will operate and maintain the
processing units that we are leasing from them and will manage the processing
of crude oil and other feedstreams by such processing units.
Coker Project Facilities. Clark Refining & Marketing will supervise and
train our operating employees as described below and will otherwise operate
and maintain our new processing units and associated equipment and will manage
the processing of feedstocks by such units.
Other Refinery Facilities. Clark Refining & Marketing is also obligated to
operate and maintain pipelines, interconnections and other Clark Refining &
Marketing equipment at the Port Arthur refinery as needed for the efficient
operation of our heavy oil processing facility and the production of products
required under our product purchase agreement with them. Clark Refining &
Marketing is also responsible for coordinating the scheduling and performance
of all maintenance, including turnarounds and unscheduled unit shutdowns, at
the Port Arthur refinery to ensure that our heavy oil processing facility will
produce the products required under our product purchase agreement.
Other Services and Supplies
Clark Refining & Marketing is also responsible for providing all other
services and supplies needed for operation of our heavy oil processing
facility including, among others:
. coordinating and managing the delivery of all final and intermediate
products from our heavy oil processing facility in accordance with our
product purchase agreement;
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. scheduling and coordinating deliveries of hydrogen to our heavy oil
processing facility pursuant to our hydrogen supply agreement with Air
Products and otherwise performing our obligations other than our payment
obligations and exercising our rights under such agreement;
. supplying additional hydrogen and other feedstocks;
. supervising and monitoring all our contracts with third parties, other
than itself and other than agreements related to our debt obligations;
. providing catalysts, chemicals and other consumable materials;
. providing our requirements for electricity, steam, natural gas, fuel gas,
water, compressed air and nitrogen;
. providing waste management, waste water treatment and sulfur and coke
transport services;
. providing alternative sulfur recovery services if our sulfur plant is
unable to process hydrogen sulfide produced by our heavy oil processing
facility;
. providing computer, radio, phone, analytical, security operations,
engineering, human resources, accounting and emergency response services;
. procuring, managing and storing all spare parts necessary for the
operation of our heavy oil processing facility;
. procuring and maintaining on our behalf a complete inventory of specified
capital spares needed for our new processing units and ensuring that such
spares are managed and stored in a manner that ensures that they are kept
separate from spares owned by them and are identifiable as our property;
. initiating, maintaining and supervising all environmental, health and
safety precautions programs related to our heavy oil processing facility;
. purchasing and maintaining required insurance on our behalf;
. determining, procuring and maintaining in effect all licenses, permits
and other governmental approvals; and
. proposing an annual budget and an operating plan and providing quarterly
reports regarding operations of our heavy oil processing facility.
Our Obligations
We are responsible for employing a specified roster of operational employees
to operate our new processing units and an accounting manager who, among other
things, is responsible for administering our contracts with Clark Refining &
Marketing, our payroll and payment of our senior debt obligations.
Compensation
Leased Facilities
We are obligated to compensate Clark Refining & Marketing for the services
and supplies provided to us by them related to the processing units that we are
leasing from them in the form of the operating fee described below under "--
Facility and Site Lease--Rent Payments--Operating Fee."
Coker Project Facilities
For each service and supply provided to us by Clark Refining & Marketing
related to our new processing units, we are obligated to pay Clark Refining &
Marketing specified monthly fees that, depending on the service or supply
provided, are based on one of the following methods:
. reimbursable costs incurred by Clark Refining & Marketing in providing
such service or supply;
. a flat fee intended to approximate the actual cost to Clark Refining &
Marketing of providing such service, which is subject to adjustment for
inflation;
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. metered usage of such service multiplied by a formula intended to
approximate a fair market price for providing such service; or
. a percentage allocation of the cost to Clark Refining & Marketing for
providing such service for the entire Port Arthur refinery which is
intended to approximate the actual usage of such service by our new
processing units.
Alternative Pricing
The pricing of fees for the services and supplies to be provided by Clark
Refining & Marketing may be adjusted during the term of the services and supply
agreement under the following three scenarios.
Change in Applicable Law. If a change in applicable law requires Clark
Refining & Marketing to make capital expenditures or change its operating
procedures and directly results in an increase in the costs to Clark Refining &
Marketing of providing any service or supply to us, we will meet and negotiate
an equitable adjustment to the pricing of such service or supply. Any such
adjustments, however, may not have a material adverse effect on our ability to
pay our senior debt obligations when they become due or payable and will not
become effective until approved by Purvin & Gertz in its role as independent
engineer.
Change in Actual Costs. If either we or Clark Refining & Marketing determine
that the price for any service or supply does not reflect accurately the actual
cost of providing such service or supply, then we will meet to negotiate an
equitable adjustment to the pricing of such service or supply. Any such
adjustments, however, may not have a material adverse effect on our ability to
pay our senior debt obligations when they become due or payable and will not
become effective until approved by Purvin & Gertz in its role as independent
engineer.
Expansion of Refinery Operations. To the extent that any expansion of
operations of Clark Refining & Marketing at the Port Arthur refinery causes an
increase in the pricing of utilities or waste management services to be
provided to us, Clark Refining & Marketing is obligated to reduce the amount
payable by us for such service so that it conforms to the pricing that would
have been in effect if such expansion had not occurred.
Processing of Feedstocks Owned by Clark Refining & Marketing
Construction Period
Prior to start-up and testing of our new processing units under our
construction contract with Foster Wheeler USA, Clark Refining & Marketing has a
right of first refusal which, if exercised, would require us to process crude
oil owned by Clark Refining & Marketing. Clark Refining & Marketing may
exercise these processing rights so long as it pays for all related operating
expenses and processing does not interfere with the performance of the upgrades
and improvements to such leased units, the construction of our coker project or
the achievement of the performance guarantees of Foster Wheeler USA related to
our coker project and will not adversely affect the reliability or the useful
life of the processing units we are leasing from Clark Refining & Marketing. We
are being compensated for granting these processing rights in the form of a
reduction in the amount of rent that otherwise would have been payable under
our facility and site lease.
Start-up Period
During start-up and performance testing of our coker project, Clark Refining
& Marketing will not have any right to require us to process crude oil owned by
Clark Refining & Marketing through our heavy oil processing facility.
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Post-Completion Period
Ancillary Equipment. After our coker project is finally complete, Clark
Refining & Marketing will have a right of first refusal each calendar quarter.
This right of first refusal, if exercised, would require us to process crude
oil owned by Clark Refining & Marketing each day in an amount up to the
portion of the actual capacity of the units in excess of either (1) the
quantity of Maya available to us under the long term crude oil supply
agreement on such day and the light sour crude oil necessary to process such
Maya or (2) if P.M.I. Comercio Internacional has curtailed the amount of Maya
available to us under our long term crude oil supply agreement, the amount of
crude oil sufficient to operate our new coker unit at 80% of its actual
capacity on such day. Clark Refining & Marketing will compensate us in the
form of a processing fee based on the number of barrels of Clark Refining &
Marketing-owned crude oil processed by us each day. The formula for
calculating this fee is intended to approximate the fixed and variable costs
of processing such Clark Refining & Marketing-owned crude oil through our
leased units. If Clark Refining & Marketing does not exercise this right, we
may sell our excess capacity to an alternative purchaser and Clark Refining &
Marketing is obligated to provide such third party the services and supplies
necessary to utilize such capacity.
Coker. Clark Refining & Marketing will also have a right of first refusal
each calendar quarter which, if exercised, would require us to process
feedstocks owned by it each day in an amount up to the excess of the volume
necessary to process the vacuum tower bottoms produced by the processing of
our crude oil through our leased units each day. We may process these
feedstocks through our delayed coking unit or, at our option, through any
other appropriate equipment to which we may have access. Clark Refining &
Marketing will compensate us in the form of a processing fee based on the
number of barrels of Clark Refining & Marketing-owned crude oil processed by
us each day. The formula for calculating this fee is intended to approximate
the fixed and variable costs of processing such Clark Refining & Marketing-
owned crude oil through our new delayed coking unit. If Clark Refining &
Marketing does not exercise this right, we may sell such capacity to an
alternative purchaser and Clark Refining & Marketing is obligated to provide
such third party the services and supplies necessary to utilize such capacity.
Hydrocracker. Clark Refining & Marketing will also have a right of first
refusal each calendar quarter which, if exercised, would require us to process
feedstocks owned by it each day in an amount up to the portion of the actual
capacity of our new vacuum gas oil hydrocracker needed to process gas oil each
day that exceeds the capacity necessary to process the gas oil produced by the
processing of our vacuum tower bottoms through our new delayed coking unit
each day. Clark Refining & Marketing will compensate us in the form of a
processing fee based on the number of barrels of Clark Refining & Marketing-
owned crude oil processed by us each day. The formula for calculating this fee
is intended to approximate the fixed and variable costs of processing such
Clark Refining & Marketing-owned crude oil through our new hydrocracker. If
Clark Refining & Marketing does not exercise this right, we may sell such
capacity, or portion of such capacity, to an alternative purchaser or direct
Clark Refining & Marketing to ensure that such capacity, or portion of such
capacity, is used to process gas oils produced by processing our crude oil
through our leased units. In either case, Clark Refining & Marketing is
obligated to provide us and/or such third party the services and supplies
necessary to utilize such capacity.
Permitted Operational Adjustments
General Modifications
Clark Refining & Marketing may modify the operations of our heavy oil
processing facility at its discretion as long as the modification does not:
. impede production of the quantity and quality specifications of products
to be provided pursuant to our product purchase agreement with them;
. cause an increase in our reimbursable costs that are payable under the
services and supply agreement which is not offset by a corresponding
increase in amounts payable to us pursuant to the product purchase
agreement;
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. adversely affect the reliability or the useful life of the processing
units comprising our heavy oil processing facility; or
. have a material adverse effect on our operations, the heavy oil
processing facility, or the Port Arthur refinery, including a material
adverse effect on our ability to pay or prepay our senior debt
obligations in accordance with the base case financial model included in
the Independent Engineer's Report annexed hereto as Annex B.
Capacity Swaps
If Clark Refining & Marketing meets specified criteria and determines, in
its reasonable business judgment and in conformity with prudent industry
practices, that it is economically and technically prudent to process our
feedstocks through another Clark Refining & Marketing processing unit at the
Port Arthur refinery having substantially the same processing capabilities as
a unit within our heavy oil processing facility, Clark Refining & Marketing
may substitute the processing capacity of such unit with Clark Refining &
Marketing's unit at our expense.
Alternative Feedstocks
To the extent that operational difficulties involving our leased units cause
their actual capacity to be less than their design capacity, Clark Refining &
Marketing must use commercially reasonable efforts to procure alternative
feedstocks on our and their behalf to (1) operate the other processing units
comprising the heavy oil processing facility at their actual capacities and
(2) to preserve the relative processing capacities as between us and Clark
Refining & Marketing as would exist if such processing units were operating at
their design capacities. In such event, we will reimburse Clark Refining &
Marketing for all reasonable expenses and expenditures they incur in procuring
such alternative feedstocks on our behalf.
Title to Product Streams
Title to product streams from our heavy oil processing facility will be
determined on a pro rata basis in proportion to the relative volume of our,
Clark Refining & Marketing's or another third party's crude oil or other
feedstocks processed through our heavy oil processing facility based on
specified formulas.
Defaults, Termination and Other Remedies
Clark Refining & Marketing Defaults
The following constitute defaults by Clark Refining & Marketing:
. failure to pay us any amount in excess of $250,000 when due that
continues uncured for five days;
. failure to perform substantially any material obligation that remains
uncured for 30 days;
. commencement of insolvency, receivership, reorganization or bankruptcy
proceedings by or against Clark Refining & Marketing, that are not
dismissed within 60 days;
. any material representation or warranty made by Clark Refining &
Marketing is proven incorrect as of the time made or deemed made that
remains uncured for 60 days;
. failure to perform substantially any material obligation under either of
our leases with Clark Refining & Marketing that remains uncured for 30
days; or
. default by Clark Refining & Marketing under the product purchase
agreement.
Subject to any additional requirements of our senior debt documents and
specified cure periods, we may terminate the services and supply agreement
upon a Clark Refining & Marketing default or exercise any other remedies
available to us at law or in equity.
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Our Defaults
Our failure to pay any amount due under the services and supply agreement in
excess of $250,000 that remains uncured for a period of 5 days constitutes a
default by us under the services and supply agreement. If we default under the
services and supply agreement, Clark Refining & Marketing may terminate the
agreement after first giving us and our financing parties 90 days notice and
the opportunity to cure such default.
Specific Performance
The parties have acknowledged that monetary damages may be an inadequate
remedy for a breach of any of the provisions of the services and supply
agreement. In such case the parties will be entitled to specific performance
of the breaching party's obligations and in any action for specific
performance the parties will waive the defense that a remedy at law would be
adequate.
Termination Option
We or Clark Refining & Marketing may terminate the services and supply
agreement if final completion of our coker project and completion of the
improvements and upgrades to our leased units does not occur by March 2002.
Force Majeure
If an event of force majeure causes a material adverse effect on a party's
ability to carry out its obligations under the services and supply agreement,
other than the obligation to pay money, such party is obligated to give prompt
notice to the other party. In such case, these obligations so far as they are
affected by such event of force majeure will be suspended during but not
longer than the continuance of such event of force majeure and such further
period thereafter as shall be reasonable in the circumstances.
An event of force majeure is any event or circumstance if (1) such event or
circumstance is beyond the reasonable control of the affected party and (2)
such event or circumstance is not the direct or indirect result of a party's
negligence or the failure of such party to perform any of its obligations
under the services and supply agreement, including, among others:
. any interruption or cessation in delivery of crude oil or other
feedstocks to the Port Arthur refinery;
. acts of God, earthquake, fire, explosion, tornado, hurricane, or other
extraordinary weather conditions more severe than those experienced at
any time in the last 30 years for the geographic area of the Port Arthur
refinery;
. acts of a public enemy, war, blockade, insurrection or riot;
. laws, rules, regulations, orders, judgments or other acts of any
foreign, federal, state or local court, administrative agency,
governmental body or authority;
. strikes, boycotts or lockouts, except any such strike, boycott or
lockout that is not national or industry-wide that involves the
employees of Clark Refining & Marketing; and
. a partial or entire interruption or other failure of (1) the supply of
electricity, water, wastewater treatment, steam, hydrogen or other
utilities to the refinery or any part thereof, or (2) pipeline service,
ship or barge service, dock access or usage or other transportation
facilities.
End of Term Obligations
Following termination of the services and supply agreement, Clark Refining &
Marketing is obligated to:
. cooperate with us so that we are able to continue operating our new
processing units, reclaim goods, equipment and materials, and accomplish
the smooth transition of operations of such units from Clark Refining &
Marketing to us or to a new manager that we engage;
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. execute all documents and take all reasonable steps that we request
needed to assign to and vest in us all rights, benefits, interest and
title in connection with any contracts or obligations that Clark
Refining & Marketing may have undertaken with third parties in
connection with the services and supply agreement;
. deliver to us all materials and documents that are our property; and
. cooperate with us to effect the transfer to us of any permits held by
Clark Refining & Marketing and required for our continuing operation of
the heavy oil processing facility.
Miscellaneous Provisions
Subcontractors
Clark Refining & Marketing has the right to subcontract any portion of the
services and supplies it is to provide us. Clark Refining & Marketing,
however, will remain primarily responsible for all of its obligations under
the services and supply agreement and we will not be deemed by virtue of any
Clark Refining & Marketing subcontract to have any contractual relationship or
obligation to any Clark Refining & Marketing subcontractors.
Dispute Resolution; Governing Law
If any dispute arises regarding the services and supply agreement, our
senior executives and those of Clark Refining & Marketing are obligated to
meet to resolve the conflict. If we cannot resolve such conflict within
specified time periods, either party may initiate an arbitration proceeding.
Such arbitration will be governed by rules of the American Arbitration
Association and the arbitration will be in New York. The services and supply
agreement is governed by the laws of the State of New York.
Assignments
Clark Refining & Marketing may not assign its rights under the services and
supply agreement without our prior written consent and the consent of the
holders of our senior debt. We may assign our rights to our senior debt
holders as collateral security for our senior debt obligations, but otherwise
we may not assign our rights under the services and supply agreement without
Clark Refining & Marketing's consent and the consent of our senior debt
holders. The assignment of our rights under the services and supply agreement
with respect to specified regulated utilities to any person will not be
effective unless our rights under the facility and site lease and the ground
lease are also assigned to such person.
Product Purchase Agreement
We and Clark Refining & Marketing entered into a product purchase agreement
in August 1999, simultaneously with the issuance of the outstanding notes.
Under this agreement Clark Refining & Marketing has an absolute and
unconditional obligation to accept and actually take delivery of all
intermediate and final products of our heavy oil processing facility that we
tender for delivery and to pay us for such products in accordance with
specified pricing formulas. Subject to the early termination rights of each
party described below, the product purchase agreement will extend for a term
of 30 years.
Required Product Mix
Unless Clark Refining & Marketing otherwise requests, we are obligated to
use commercially reasonable efforts to meet specified target quantity and
quality specifications of products to be delivered to Clark Refining &
Marketing. We will, however, have no liability for failing to deliver such
target specifications of products.
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Clark Refining & Marketing, as our customer under the product purchase
agreement, may request that we alter the quality and quantity of products
produced by our heavy oil processing facility. In this case, we are obligated
to use commercially reasonable efforts to meet the requested product
specifications. These adjustments to the product mix produced by our heavy oil
processing facility, however, are subject to the following conditions:
. in a given calendar month, such adjustments may not cause our leased
equipment to process less than the volume of Maya available to us under
the long term crude oil supply agreement or, if the availability of such
Maya has been curtailed, less than the amount of crude oil or other
feedstocks sufficient to utilize 80% of the actual capacity of our leased
units;
. in a given calendar month, such adjustments may not cause our new delayed
coker to process less than all the vacuum tower bottoms produced by
processing our crude oil through our leased units;
. such adjustments will, in Clark Refining & Marketing's reasonable good
faith judgment, maximize the profitability at the Port Arthur refinery as
a whole and be mutually beneficial to Clark Refining & Marketing and us;
. Clark Refining & Marketing will supply us with the necessary feedstocks
under the services and supply Agreement and make any needed operational
and other adjustments under such agreement to fulfill such request;
. such adjustments will not materially increase our net reimbursable costs
payable under the services and supply agreement and not adversely affect
the reliability, useful life of, or have a material adverse effect on the
physical condition of our heavy oil processing facility; and
. it is feasible for our heavy oil processing facility to produce the
quantity and quality of products requested.
Product Prices
The product purchase agreement includes pricing formulas for each product
expected to be produced by our heavy oil processing facility. These formulas
are intended to reflect fair market pricing of these products and will be used
to determine the amounts payable to us by Clark Refining & Marketing. To the
extent, however, that any of our products are purchased by Clark Refining &
Marketing and immediately resold to a non-affiliated third party, the price
payable to us by Clark Refining & Marketing for such product will be the
purchase price received by Clark Refining & Marketing from such third party
less a specified marketing fee. This 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 would be incurred whether we
sold the products directly or paid Clark Refining & Marketing or another third
party to do so on our behalf. We will invoice Clark Refining & Marketing every
three calendar days and Clark Refining & Marketing will be obligated to pay
invoices within five calendar days of receipt.
Price Adjustments for Non-Specification Products
If a material amount of any product produced our the heavy oil processing
facility fails to meet the target specifications used to develop the pricing
formulas for the product and the failure to meet specifications has a material
adverse affect on the fair market value of such product or any finished
product derived from such product, then we will meet with Clark Refining &
Marketing to negotiate a good faith and equitable adjustment to payments due
us. Any such adjustment, however, will be conditioned on the following:
. that the failure to meet specifications was not caused by a failure of
Clark Refining & Marketing to operate our heavy oil processing facility
in accordance with its obligations under the services and supply
agreement;
. the non-specification product was not requested by Clark Refining &
Marketing; and
. the adjustment will be effective until Purvin & Gertz, as independent
engineer, issues a certificate approving the reasonableness of such
adjustment.
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If a failure to meet product specifications is due to a design or
construction defect of the coker project and the failure is expected to
continue, we will meet with Clark Refining & Marketing to negotiate adjustments
to the applicable formulas in good faith. Such adjustments, however, will not
be effective until Purvin & Gertz, as independent engineer, issues a
certificate approving the reasonableness of such adjustment.
Defaults, Termination and Other Remedies
Clark Refining & Marketing Defaults
The following constitute defaults by Clark Refining & Marketing:
. failure to pay us any amount in excess of $250,000 when due that
continues uncured for five days;
. failure to perform substantially any material obligation that remains
uncured for 30 days;
. commencement of insolvency, receivership, reorganization or bankruptcy
proceedings by or against Clark Refining & Marketing that are not
dismissed within 60 days;
. any material representation or warranty made by Clark Refining &
Marketing is proven incorrect as of the time made or deemed made that
remains uncured for 60 days;
. failure to perform substantially any material obligation under either of
our leases with Clark Refining & Marketing that remains uncured for 30
days; or
. default by Clark Refining & Marketing under the services and supply
agreement.
Subject to the consent of our senior debt holders, we may terminate the
product purchase agreement upon a Clark Refining & Marketing default or
exercise any other remedies available to us at law or in equity.
Our Defaults
Our material failure to deliver products substantially as required under the
product purchase agreement for a period of 60 days constitutes a default under
the product purchase agreement. If a default occurs, Clark Refining & Marketing
may terminate the agreement after first giving us and our senior debt holders
90 days notice and opportunity to cure the default.
Specific Performance
The parties have acknowledged that monetary damages may be an inadequate
remedy for a breach of any of the provisions of the product purchase agreement
and that in such case the parties will be entitled to specific performance of
the breaching party's obligations. The parties have agreed that in any action
for specific performance will waive the defense that a remedy at law would be
adequate.
Termination Option
We or Clark Refining & Marketing may terminate the product purchase agreement
if final completion of our coker project does not occur by March 2002.
Force Majeure
If an event of force majeure causes a material adverse effect on a party's
ability to carry out its obligations under the product purchase agreement,
other than the obligation to pay money that party is obligated to give to the
other party prompt notice. In such case the party's obligations so far as they
are affected by such event of force majeure will be suspended during but not
longer than the continuance of such event of force majeure and such further
period thereafter as shall be reasonable in the circumstances. For the purposes
of the product purchase agreement, an event of force majeure will have the same
meaning as it is used in the services and supply agreement and described under
the caption "--Services and Supply Agreement--Force Majeure" above.
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Miscellaneous Provisions
Dispute Resolution; Governing Law
If any dispute arises regarding the product purchase agreement, our senior
executives and those of Clark Refining & Marketing are obligated to meet to
resolve the conflict. If we cannot resolve the conflict within specified time
periods, either party may initiate an arbitration proceeding. The arbitration
will be governed by the rules of the American Arbitration Association and the
arbitration will be in New York. The product purchase agreement is governed by
the laws of the State of New York.
Assignments
Clark Refining & Marketing may not assign its rights under the product
purchase agreement without our prior written consent and the consent of the
holders of our senior debt. We may assign our rights to our senior debt holders
as collateral security for our senior debt obligations, but otherwise we may
not assign our rights under the product purchase agreement without Clark
Refining & Marketing's consent and the consent of our senior debt holders.
Facility and Site Lease
We and Clark Refining & Marketing entered into a facility and site lease in
August 1999, simultaneously with the issuance of the outstanding notes. Under
this lease, we are leasing Clark Refining & Marketing's crude unit and vacuum
tower, two of its distillate hydrotreaters and its naphtha hydrotreater. These
units are located at the Port Arthur refinery. The initial term of this lease
is 30 years. We may renew the lease for five additional five-year terms.
Easement
Clark Refining & Marketing has also granted us a nonexclusive blanket
easement over and under the remaining Port Arthur refinery property necessary
to own, construct and operate our coker project and to maintain and operate the
units leased to us.
Ancillary Equipment Upgrade
Construction Obligations
Clark Refining & Marketing is obligated under the facility and site lease to
construct and substantially complete, specified improvements and upgrades to
the processing units we are leasing before October 2000, at its cost and
expense. If Clark Refining & Marketing fails to complete such improvements and
upgrades on time, we may engage our own contractor to complete the work at
Clark Refining & Marketing's expense.
Assignment of Construction Contract
As security for its obligation to perform these improvements and upgrades,
Clark Refining & Marketing has collaterally assigned to us all its right, title
and interest in and to any and all construction, design, engineering or
procurement contracts that it enters into for purpose of completing such
improvements.
Rent Payments
In the opinion of Purvin & Gertz, the following rent payments represent fair
market rental payments for the facility and site lease term.
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Base Rent
After start-up of our coker project, we will begin making ongoing quarterly
rent payments to Clark Refining & Marketing equal to approximately $8 million,
or a smaller pro-rated amount in the first quarter when the payments are due.
This rent amount will be adjusted over time in proportion to changes in the
producer price index published by the U.S. Department of Labor.
Operating Fee
As additional rent, we will pay Clark Refining & Marketing an operating fee
each month after start-up of our coker project for the services and supplies
provided to us by Clark Refining & Marketing under the services and supply
agreement and related to the on-going operation of our leased units. Such
operating fee is based on the number of barrels of crude oil and other
feedstocks processed through our leased units and is intended to approximate
the fixed and variable costs to Clark Refining & Marketing of providing
services and supplies for such leased units.
This operating fee may be adjusted if Clark Refining & Marketing incurs
increased costs for purchases of catalysts or other consumable materials or
other expenses related to its operation of our leased equipment which are
intended to increase our net revenues. In such circumstances, we and Clark
Refining & Marketing are to negotiate in good faith an equitable adjustment to
the calculation of the operating fee to reflect the increased costs. Any such
adjustment may not have a material adverse effect on our ability to operate in
accordance with the base case financial model and will not become effective
until approved by the independent engineer.
Governing Law
The facility and site lease is governed by the laws of the State of Texas.
Ground Lease
Simultaneously with the issuance of the outstanding notes in August 1999, we
entered into a ground lease with Clark Refining & Marketing. Under this lease,
we are leasing from Clark Refining & Marketing the sites within the Port Arthur
refinery on which our new processing units will be located. The initial term of
the ground lease is 30 years. We may renew the ground lease for five additional
five-year terms.
Easements
Blanket Easement
Clark Refining & Marketing has granted us a nonexclusive easement over and
under the remaining Port Arthur refinery property as necessary to own,
construct and operate our coker project and maintain and operate the units
leased to us.
Dock Easement
Clark Refining & Marketing has also granted us a nonexclusive easement over
the docks owned by Clark Refining & Marketing located adjacent to the Port
Arthur refinery for the unloading of cargoes of crude oil and other feedstocks,
loading of products of our new processing units, and the construction and
maintenance of pipes, pumps, valves, gauges and other equipment in connection
with the loading and unloading.
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Oil Transportation Rights
Clark Refining & Marketing has also granted us a nonexclusive easement over
and under pipelines and oil handling facilities needed for the transportation
of crude oil to the Port Arthur refinery from the docking facilities of Sun
Pipe Line Company in Nederland, Texas.
License to use Additional Facilities
Clark Refining & Marketing also granted us a license to use additional
facilities located on the easements that it granted us and that are necessary
for the ongoing operation of our new processing units. These facilities
include, among others, the following locations at the refinery:
. the saturated gas plant;
. an amine treating unit and sour water stripper;
. the wastewater treatment plant;
. specified boiler houses, pump houses, power stations and cooling towers;
. specified storage tanks;
. the lye plant;
. specified crude oil pipelines;
. the hydrogen gathering, gas, steam and electrical systems;
. the flare and control systems; and
. maintenance, storehouse, rail and lab facilities.
Rent Payments
Upon the issuance of the outstanding notes, we paid Clark Refining &
Marketing $25,000 as a full prepayment of rent for the initial 30 year term of
the ground lease. In the opinion of Purvin & Gertz, this is an arm's length
rental payment for the initial term of the ground lease. Rental payments for
any renewal terms for this lease will be determined in accordance with a fair
market rental valuation procedure described in detail in the lease.
End of Term
At the end of the term of the ground lease, we have the option of abandoning
our units in place or dismantling and removing them, provided we repair any
damage to the land done by our dismantling and removal of the units.
Governing Law
The ground lease is governed by the laws of the State of Texas.
Hydrogen Supply Agreement
General
We have entered into a hydrogen supply agreement with Air Products and
Chemicals, Inc. Under the hydrogen supply agreement, Air Products will supply
us the hydrogen produced at the new hydrogen supply plant at the Port Arthur
refinery.
Construction of the Facility
Air Products is obligated to design and construct the hydrogen supply plant
according to agreed upon milestones and specifications. We and the independent
engineer have the right upon reasonable written notice to Air Products to
inspect the ongoing construction of the hydrogen supply plant.
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Term
The initial term of the hydrogen supply agreement will commence on the date
the hydrogen supply plant is installed and "ready for commercial operation,"
and will continue for 246 consecutive months. However, if we begin taking
hydrogen between October 2000 and December 2000, the initial term will be
reduced by six days for each day after October 2000 but before December 2000
that we have begun taking hydrogen. Thereafter, the hydrogen supply agreement
will remain in force from year to year unless terminated in accordance with the
hydrogen supply agreement.
Liquidated Damages for Delay in Construction
If Air Products' hydrogen supply plant fails to be ready for commercial
operation on or before December 2000, then for each day of delay beyond
December 2000 due to Air Product's acts or omissions, Air Products will pay us
liquidated damages of $19,250 for each day of delay up to $1.2 million. If we
are unable to take the hydrogen on or before December 2000 due to our acts or
omissions, we will pay Air Products liquidated damages of $38,500 for each day
of delay up to approximately $1.2 million.
Delivery of Hydrogen
Hydrogen meeting required specifications will be delivered by Air Products to
us at a specified location at the heavy oil processing facility. Title and risk
of loss with respect to hydrogen will pass from Air Products to us at that
delivery point.
Quantities and Pricing of Hydrogen
Air Products will supply and we will purchase all of our requirements for
hydrogen for use by us at the Port Arthur refinery in excess of the amount of
hydrogen produced internally at the Port Arthur refinery up to a maximum
quantity of 80 million standard cubic feet per day at the price of $1.278 per
thousand standard cubic feet. This price is subject to adjustment according to
a formula based on inflation indices. In the event we have requirements for
hydrogen in excess of this maximum daily amount, we may purchase such
additional hydrogen at the price of $1.585 per thousand standard cubic feet. In
the event we wish to increase the maximum daily amount, we and Air Products
will negotiate in good faith the price, terms and conditions for such increase.
Air Products has the right to supply any hydrogen required by us above this
maximum daily amount by matching the terms and conditions obtained by us for
such additional hydrogen requirements from a bona fide third party supplier.
We will pay Air Products for a minimum quantity of hydrogen equal to 5,018.7
million standard cubic feet per calendar quarter, regardless of the quantity of
hydrogen actually taken by us, except for periods of scheduled maintenance
activities of up to 28 days every two years. In the event the maximum daily
amount is increased for any reason, this minimum quantity of hydrogen will be
increased on a proportional basis. Furthermore, Air Products may charge us a
non-consumption charge for shortfalls in our hydrogen purchase activity.
We will also pay Air Products a monthly base facility charge of $81,839. This
price is subject to adjustment pursuant to a formula based on inflation
indices.
In the event the hydrogen supply plant is not operating or its production is
curtailed, Air Products will supply us with our requirements for hydrogen up to
the maximum daily amount, provided hydrogen is available for delivery as
reasonably determined by Air Products from the pipeline network owned and
operated by Air Products or its affiliates. The price for this hydrogen will be
$1.585 per thousand standard cubic feet. These prices are subject to adjustment
pursuant to a formula based on inflation indices.
Performance Guarantee
Air Products guarantees that it will produce and deliver hydrogen requested
by us with a minimum on-stream factor of 98%. "On-stream factor" means the
ratio of total hours in the year during which hydrogen meeting the
specifications was or could have been supplied by Air Products but for the
occurrence of events of
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force majeure or scheduled maintenance outages by Air Products to total number
of hours during that year. For each hour that the on-stream factor is greater
than 98%, a bonus in the amount of $5,200 per hour will be paid by us to Air
Products, and for each hour that the on-stream factor is less than 98%, Air
Products will pay us liquidated damages in the amount of $5,200 per hour. The
maximum amount of the bonus will be $900,000 per year and the maximum amount of
the liquidated damages will be $1.8 million per year.
Air Products is also guaranteeing the performance of specified hydrogen
compressors which are part of the hydrogen supply plant up to specified
performance specifications.
Governmental Requirements
If, in Air Products judgment, the facilities producing hydrogen for delivery
to us must be modified or tests, studies or any other action must be undertaken
with respect to such facilities to comply with any anticipated, proposed or
final regulation, law or other governmental requirement, Air Products or the
hydrogen supply plant owner must take such action following (1) in the case of
a final governmental requirement, consultation with us concerning the
anticipated costs and expenses to confirm that there is not a more cost
effective manner to comply with such final governmental requirement or (2) in
the case of an anticipated or proposed governmental requirement, our consent,
which consent will not be unreasonably withheld. Air Products must also have
given us prompt notice of its knowledge of any proposed governmental
requirement. The costs and expenses of such modifications, tests or other
action, including both fixed and variable costs, additional operating costs,
applicable overheads, general and administrative expenses, financing charges
and a reasonable fee, all in accordance with Air Products's normal accounting
practices, will be promptly reimbursed to Air Products by us as such costs and
expenses are incurred.
Contaminants
It is understood and contemplated by the parties that the hydrogen supply
plant is designed to use utilities and air containing only normal contaminants
and, therefore, if contaminants in the utilities or air, or changes in the
construction or operation of facilities in or about the Port Arthur refinery,
justify the relocation, repair, modification or removal of any equipment
comprising the hydrogen supply plant or the installation of additional
equipment, Air Products will notify us. In such case, at our election, Air
Products will either (1) make the relocation, repair, modification, or removal
or (2) install the additional equipment. We will reimburse Air Products for any
extra costs incurred and a reasonable fee all in accordance with Air Products's
normal accounting practices as such costs are incurred.
Licensing, Permits and Approvals
Each party will obtain, in a timely fashion, and maintain in effect,
including all renewals and updates thereof, any and all professional licenses,
permits or other government approvals necessary to perform its obligations and
any activities related to the hydrogen supply supply agreement, including,
without limitation, air emissions permits from the Texas Natural Resource
Conservation Commission.
Compliance with Law and Prudent Industry Standards
Each party will perform its obligations and any activities related to the
hydrogen supply agreement in compliance with all applicable laws and permits
and in accordance with prudent industry standards, will not undertake any act
or omission which will cause the other party to fail to comply with applicable
laws and permits and will be in accordance with prudent industry standards.
Neither party will undertake any act or omission which would cause or be likely
to cause it or the other party to be subject to regulation as an "electric
utility," "electric corporation," "electrical company," "public utility,"
"retail electric utility" or a "public utility holding company," as such terms
may be revised from time to time, under any applicable laws.
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Taxes
Air Products will bear and pay all federal, state, and local taxes based
upon or measured by its net income, and all franchise taxes based upon its
existence or its general right to transact business. The prices stated in the
hydrogen supply agreement do not include any taxes, charges, or fees other
than as stated in the prior sentence. Any other taxes imposed on the hydrogen
supply plant, the hydrogen supply plant site, the inventory, or upon the
operation or maintenance of the hydrogen supply plant, or upon or measured by
the production, manufacture, storage, sale, transportation, delivery, use or
consumption of hydrogen, such taxes, charges, or fees will be paid directly by
us.
Force Majeure
Neither party will be considered to have defaulted in the performance of its
obligations or to be liable in damages for failure or delay in performance
which is due to force majeure, other than the obligation to pay money,
provided that the excuse of performance will be of no greater scope and no
longer duration than is reasonably required because of the force majeure. For
purposes of the hydrogen supply agreement, "force majeure" will include any
act or event that prevents or delays the performance by either party of its
obligations under the hydrogen supply agreement if and to the extent:
. that act or event is beyond such party's reasonable control and not the
result of such party's fault or negligence;
. that party has been unable to overcome the consequences of such act or
event by the exercise of reasonable commercial efforts, which may include
the reasonable expenditure of funds; and
. that party has given the other party notice within 10 days of the party's
knowledge of the act or event giving rise to the force majeure.
Subject to the satisfaction of the foregoing conditions, force majeure will
include, but not be limited to, the following acts or events, or any
similar and equally serious acts or events which prevent or delay the
performance by a party of its obligations under the hydrogen supply
agreement:
. acts of God, fires, explosions, vapor releases, natural disasters,
floods, perils of the sea, lightning or wind;
. acts of the public enemy, wars, sabotage, insurrections, riots, strikes,
boycotts or lockouts, vandalism, blockages or accidents or failure of
equipment or machinery, except any strike, boycott or lockout that
involves Air Products' or our employees and is not national or industry-
wide or is not caused by the other party's employees;
. acts by Air Products, in the case of us, or acts by us or Clark Refining
& Marketing, in the case of Air Products;
. a determination that such party is subject to regulation as an electric
utility under applicable law regardless of whether delivery of power is
prevented, ability to obtain or maintain any easement, rights-of-way,
permit or license, actions of a court or public authority;
. labor disputes, boycotts; and
. allocation or failure of normal sources of supply of materials,
transportation, energy or utilities or other causes of a similar or
dissimilar nature.
Under no circumstances will inability to pay monies or other economic
difficulty be construed to constitute force majeure, frustration or
impossibility of performance.
The affected party will promptly give notice to the other party and use all
reasonable efforts to remedy its inability to perform. Neither party, however,
will be required to bring to an end any strike or other concerted act of
workers.
Warranty
Air Products warrants that hydrogen delivered to us will conform to the
specification set forth in the hydrogen supply agreement, and that at the time
of delivery Air Products will have good title and right to transfer the same
and that the same will be delivered free and clear of any lien or other
encumbrances.
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Limitation of Liability
Determination of the suitability of the hydrogen furnished for the use by us
is our sole responsibility, and Air Products will have no responsibility for
this determination.
We acknowledged in the hydrogen supply agreement that there are hazards
associated with the use of hydrogen, that we understand such hazards, and that
it is our responsibility to warn and protect our employees and others exposed
to such hazards through our use of hydrogen. We will hold harmless, indemnify
and defend Air Products from and against any liability incurred by Air Products
because those warnings were not made. We have assumed all risk and liability
for loss, damages or injury to persons or to our property or others arising out
of the presence or use of hydrogen or from the failure to make those warnings.
Except as expressly provided in the hydrogen supply agreement, Air Products
will not be liable in contract or tort for any other direct damages. Except in
the case of willful misconduct of Air Products, Air Products will not be liable
in contract or tort for any indirect, special, incidental, or consequential
damages, including by way of illustration and not of limitation, loss of use,
loss of work in process, down time or loss of profits, and such limitation on
damages will survive failure of an exclusive remedy.
Termination
The hydrogen supply agreement may be terminated by either party on account of
any material default of the other in carrying out the terms of the agreement
subject to a 60-day grace period. We will not terminate the hydrogen supply
agreement without the consent of our financing parties.
Either party may terminate the hydrogen supply agreement as of the expiration
of the initial supply term or the expiration of any anniversary date thereafter
by giving not less than 36 months' prior written notice to the other party.
With the consent of Clark Refining & Marketing, we may terminate the hydrogen
supply agreement for lack of requirements for hydrogen following contract year
10 if our management reasonably determines that our use of hydrogen at the Port
Arthur refinery will permanently cease following such determination and Clark
Refining & Marketing concurrently terminates the product supply agreement
between Clark Refining & Marketing and Air Products. Our right of termination
will be exercisable by our giving Air Products 12-months prior written notice
and paying to Air Products a specified termination payment which ranges from
$7.75 million to $54.4 million, depending on the number of years remaining in
the initial term.
Clark Refining & Marketing is a party to a separate contract with Air
Products under which Clark Refining & Marketing purchases electricity, steam
and hydrogen from Air Products and provides utilities to Air Products. If this
contract is terminated, we have the option of assuming Clark Refining &
Marketing's obligations under the contract. If we do not assume this contract,
Air Products will be excused from delivering hydrogen to us.
Assignment
Upon notice to the other party, any or all of a party's rights, title and
interest under the hydrogen supply agreement may be assigned to an affiliate, a
joint venture company in which such party or its affiliate is general partner
or in which such party owns at least 50% of any equity, or to any financial
institution or other entity or groups thereof under the terms of financing
arrangements. In the event of such an assignment other than a collateral
assignment, the assignor will execute for the benefit of the other party a
guarantee or similar agreement guaranteeing the performance of the obligations
under the hydrogen supply agreement by the assignee. If any of our financing
parties or trustees or agents acting on their behalf, or their nominees or
assignees, succeeds to our rights under this hydrogen supply agreement as a
result of foreclosure or similar arrangement in lieu of foreclosure, Air
Products will attorn to and recognize such successor as the buyer under
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the hydrogen supply agreement and that successor will be bound by the terms and
conditions of the hydrogen supply agreement. The hydrogen supply agreement will
not otherwise be assignable or transferable by either us or Air Products
without the prior written consent of the other, which consent will not be
unreasonably withheld. Any attempted assignment or transfer without such
consent will be void.
Dispute Resolution; Governing Law
The parties will endeavor to resolve any dispute arising out of or relating
to the hydrogen supply agreement by mediation under the rules and guidelines of
the American Arbitration Association. Any controversy or claim arising out of
or relating to the hydrogen supply agreement or the breach, termination or
validity of the hydrogen supply agreement, which remains unresolved 45 days
after appointment of a mediator, will be settled by arbitration by three
arbitrators in accordance with the rules and guidelines of the American
Arbitration Association. Judgment upon the award rendered by the arbitrators
may be entered by any court having jurisdiction. The hydrogen supply agreement
will be interpreted in accordance with and governed by the laws of the State of
New York.
Marine Dock and Terminaling Agreement
Clark Refining & Marketing 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 Clark
Refining & Marketing's pipeline located on Sun Pipe Line's property. This
agreement also provides for the delivery of our crude oil.
Term
The marine dock and terminaling agreement will be in effect until August 2000
and will be deemed automatically extended for additional one year periods
unless either party gives six months notice to the other party.
Facilities and Services to be Provided by Sun
Facilities to be Provided by Sun Pipe Line for Clark Refining & Marketing's
Non-exclusive Use
. terminaling facilities consisting of lines, pipes, gauges and berths to
receive and deliver crude oil
. tankage facilities to store crude oil
Services to be Performed by Sun Pipe Line
. receive deliveries of crude oil for Clark Refining & Marketing and its
affiliates at the terminaling facility
. receive, store and deliver crude oil through tanks designated for Clark
Refining & Marketing in accordance with Clark Refining & Marketing's
instructions
Properties of the Crude Oil
Clark Refining & Marketing represents that the crude oil to be delivered to
Sun Pipe Line can be handled in conventional non-heated crude oil tankage and
pipeline systems. The crude oil is required to have properties within specified
limits which include Maya. Sun Pipe Line has the right to test whether the
crude oil conforms with these specifications.
Fees
Sun Pipe Line charges Clark Refining & Marketing the following fees:
. throughput fees of $0.07 per barrel for a monthly average throughput
volume of up to 70,000 barrels per day and $0.06 per barrel for all
throughput in excess of 70,000 barrels per day; and
. a tank rental fee of $0.16 per barrel for 15 days of storage and an
ability to extend to 30 days.
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Force Majeure
In the event either party is unable to carry out its non-monetary obligations
under the marine dock and terminaling agreement due to force majeure, the
obligations of both parties will be suspended during the continuance of the
inability. The term "force majeure" will include, among other things, the
following:
. acts of God, storms, floods, breakage, accident to machinery or lines of
pipe, washouts;
. acts of the public enemy, wars, blockades, insurrections, riots, civil
disturbances, arrests, the order of any court or governmental authority
having jurisdiction, explosions;
. strikes, lockouts or other industrial disturbances; and
. inability to obtain, or unavoidable delay in obtaining, material,
equipment, right of way easements, franchises or permits.
Sun Pipe Line may also require Clark Refining & Marketing to remove a portion
of its crude oil in storage to comply with strategic petroleum reserve
requirements in event of a national emergency.
Title and Responsibility
Title to crude oil delivered to the terminal will always remain with Clark
Refining & Marketing or its affiliates. Sun Pipe Line's custodial
responsibility for the crude oil commences when the crude oil enters the flange
connection of its 30-inch dock line at the discharge line of Clark Refining &
Marketing's vessel. Sun Pipe Line's custodial responsibility terminates upon
Clark Refining & Marketing's receipt at the Doe Manifold preceding Clark
Refining & Marketing's scraper trap with the 32-inch pipeline which continues
to the refinery property.
Assignment
Either party may assign its interests under the marine dock and terminaling
agreement with the consent of the other party. Furthermore, either party may
assign its interests to a subsidiary or affiliated company, provided that the
original party remains liable for full performance. Sun Pipe Line may assign
its interests to a purchaser of the terminal if it or any part should be sold.
Clark Refining & Marketing may assign its interests in connection with any sale
of the Port Arthur refinery or to any lender or collateral trustee in
connection with the financing relating to the construction involving the Port
Arthur refinery.
Governing Law
The marine dock and terminaling agreement is governed by and construed in
accordance with the laws of the State of Texas.
Reimbursable Construction Contract
Clark Refining & Marketing entered into a reimbursable construction contract
with Foster Wheeler USA in March 1998 for construction of the refinery upgrade
project. The reimbursable construction contract was amended in July 1999 to
remove our coker project from Foster Wheeler USA's scope of work thereunder and
conform the insurance requirements thereunder to those in the construction
contract for our coker project. The scope of work in the reimbursable
construction contract now includes the renovation and upgrade of the crude
unit, vacuum tower and other ancillary equipment required to be performed by
Clark Refining & Marketing under the facility and site lease. Under this
reimbursable construction contract, Clark Refining & Marketing will pay Foster
Wheeler USA based on the actual costs incurred by Foster Wheeler USA plus a
profit margin rather than a fixed-cost basis. Clark Refining & Marketing is
required to maintain a standby letter of credit to ensure that funds are
available for payments to Foster Wheeler USA under the reimbursable
construction contract. The initial amount of the letter of credit was $97
million and is required to be reduced over time by payments made by Clark
Refining & Marketing to Foster Wheeler USA. Foster Wheeler USA has agreed to
draw on the letter of credit and place the proceeds into an escrow account with
the collateral trustee for our senior debt if the letter of credit is not
renewed within 15 days prior to its expiration. Foster Wheeler USA has also
separately agreed with the collateral trustee not to draw on the letter of
credit or withdraw funds from the escrow account unless Purvin & Gertz, in its
role as independent engineer, has certified that the work related to the
requested drawing has been performed and the amounts requested are due and
payable.
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THE EXCHANGE OFFER
Purpose and Effect of the Exchange Offer
We have entered into a registration rights agreement with the initial
purchasers of the outstanding notes in which we agreed to file a registration
statement relating to an offer to exchange the outstanding notes for exchange
notes. We agreed to use our reasonable best efforts to cause such registration
statement to become effective within 240 days following the original issue of
the outstanding notes and to pay additional interest on the outstanding notes
if the exchange offer is not consummated within 270 days following the original
issue of outstanding notes. The exchange notes will have terms substantially
identical to the outstanding notes; except that the exchange notes will not
contain terms with respect to transfer restrictions, registration rights and
additional interest for failure to observe specified obligations in the
registration rights agreement. The outstanding notes were issued on August 19,
1999.
Under the circumstances set forth below, we will use our reasonable best
efforts to cause the Commission to declare effective a shelf registration
statement with respect to the resale of the outstanding notes and keep the
statement effective for up to two years after the effective date of the shelf
registration statement. These circumstances include:
. if any changes in law, Commission rules or regulations or applicable
interpretations thereof by the staff of the Commission do not permit us
to effect the exchange offer as contemplated by the registration rights
agreement;
. if any outstanding notes validly tendered in the exchange offer are not
exchanged for exchange notes within 270 days after the original issue of
the outstanding notes;
. if any initial purchaser of the outstanding notes so requests, but only
with respect to any outstanding notes not eligible to be exchanged for
exchange notes in the exchange offer; or
. if any holder of the outstanding notes notifies us that it is not
permitted to participate in the exchange offer or would not receive
fully tradable exchange notes pursuant to the exchange offer.
If we fail to comply with specified obligations under the registration rights
agreement, we will be required to pay additional interest to holders of the
outstanding notes. Please read the section captioned "Registration Rights
Agreement" for more details regarding the registration rights agreement and the
circumstances under which we will be required to pay additional interest.
Each holder of outstanding notes that wishes to exchange such outstanding
notes for transferable exchange notes in the exchange offer will be required to
make the following representations:
. any exchange notes will be acquired in the ordinary course of its
business;
. such holder has no arrangement with any person to participate in the
distribution of the exchange notes; and
. such holder is not our "affiliate," as defined in Rule 405 of the
Securities Act, or if it is our affiliate, that it will comply with
applicable registration and prospectus delivery requirements of the
Securities Act.
Resale of Exchange Notes
Based on interpretations of the Commission staff set forth in no action
letters issued to unrelated third parties, we believe that exchange notes
issued under the exchange offer in exchange for outstanding notes may be
offered for resale, resold and otherwise transferred by any exchange note
holder without compliance with the registration and prospectus delivery
provisions of the Securities Act, if:
. such holder is not an "affiliate" of Port Arthur Finance within the
meaning of Rule 405 under the Securities Act;
. such exchange notes are acquired in the ordinary course of the holder's
business; and
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. the holder does not intend to participate in the distribution of such
exchange notes.
Any holder who tenders in the exchange offer with the intention of
participating in any manner in a distribution of the exchange notes
. cannot rely on the position of the staff of the Commission enunciated in
"Exxon Capital Holdings Corporation" or similar interpretive letters;
and
. must comply with the registration and prospectus delivery requirements
of the Securities Act in connection with a secondary resale transaction.
This prospectus may be used for an offer to resell, resale or other
retransfer of exchange notes only as specifically set forth in this prospectus.
With regard to broker-dealers, only broker-dealers that acquired the
outstanding notes as a result of market-making activities or other trading
activities may participate in the exchange offer. Each broker-dealer that
receives exchange notes for its own account in exchange for outstanding notes,
where such outstanding notes were acquired by such broker-dealer as a result of
market-making activities or other trading activities, must acknowledge that it
will deliver a prospectus in connection with any resale of the exchange notes.
Please read the section captioned "Plan of Distribution" for more details
regarding the transfer of exchange notes.
Terms of the Exchange Offer
Upon the terms and subject to the conditions set forth in this prospectus and
in the letter of transmittal, Port Arthur Finance will accept for exchange any
outstanding notes properly tendered and not withdrawn prior to the expiration
date. Port Arthur Finance will issue $1,000 principal amount of exchange notes
in exchange for each $1,000 principal amount of outstanding notes surrendered
under the exchange offer. Outstanding notes may be tendered only in integral
multiples of $1,000.
The form and terms of the exchange notes will be substantially identical to
the form and terms of the outstanding notes except the exchange notes will be
registered under the Securities Act, will not bear legends restricting their
transfer and will not provide for any additional interest upon failure of Port
Arthur Finance to fulfill its obligations under the registration rights
agreement to file, and cause to be effective, a registration statement. The
exchange notes will evidence the same debt as the outstanding notes. The
exchange notes will be issued under and entitled to the benefits of the same
indenture that authorized the issuance of the outstanding notes. Consequently,
both series will be treated as a single class of debt securities under that
indenture. For a description of the indenture, see "Description of Notes"
below.
The exchange offer is not conditioned upon any minimum aggregate principal
amount of outstanding notes being tendered for exchange.
As of the date of this prospectus, $255 million aggregate principal amount of
the outstanding notes are outstanding. This prospectus and the letter of
transmittal are being sent to all registered holders of outstanding notes.
There will be no fixed record date for determining registered holders of
outstanding notes entitled to participate in the exchange offer.
Port Arthur Finance intends to conduct the exchange offer in accordance with
the provisions of the registration rights agreement, the applicable
requirements of the Securities Act and the Securities Exchange Act of 1934 and
the rules and regulations of the Commission. Outstanding notes that are not
tendered for exchange in the exchange offer will remain outstanding and
continue to accrue interest and will be entitled to the rights and benefits
such holders have under the indenture relating to the outstanding notes and the
registration rights agreement.
Port Arthur Finance will be deemed to have accepted for exchange properly
tendered outstanding notes when we have given oral or written notice of the
acceptance to the exchange agent. The exchange agent will act as agent for the
tendering holders for the purposes of receiving the exchange notes from us and
delivering
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exchange notes to such holders. Subject to the terms of the registration rights
agreement, Port Arthur Finance expressly reserves the right to amend or
terminate the exchange offer, and not to accept for exchange any outstanding
notes not previously accepted for exchange, upon the occurrence of any of the
conditions specified below under the caption "--Certain Conditions to the
Exchange Offer."
Holders who tender outstanding notes in the exchange offer will not be
required to pay brokerage commissions or fees or, subject to the instructions
in the letter of transmittal, transfer taxes with respect to the exchange of
outstanding notes. We will pay all charges and expenses, other than the
applicable taxes described below under "--Fees and Expenses", in connection
with the exchange offer. It is important that you read the section labeled "--
Fees and Expenses" below for more details regarding fees and expenses incurred
in the exchange offer.
Expiration Date; Extensions; Amendments
The exchange offer will expire at 5:00 p.m., New York City time on ,
2000, unless in its sole discretion, Port Arthur Finance extends it.
In order to extend the exchange offer, Port Arthur Finance will notify the
exchange agent orally or in writing of any extension. Port Arthur Finance will
notify the registered holders of outstanding notes of the extension no later
than 9:00 a.m., New York City time, on the business day after the previously
scheduled expiration date.
Port Arthur Finance reserves the right, in its sole discretion:
. to delay accepting for exchange any outstanding notes;
. to extend the exchange offer or to terminate the exchange offer and to
refuse to accept outstanding notes not previously accepted if any of the
conditions set forth below under "--Conditions to the Exchange Offer"
have not been satisfied, by giving oral or written notice of such delay,
extension or termination to the exchange agent; or
. subject to the terms of the registration rights agreement, to amend the
terms of the exchange offer in any manner.
Any such delay in acceptance, extension, termination or amendment will be
followed as promptly as practicable by oral or written notice thereof to the
registered holders of outstanding notes. If Port Arthur Finance amends the
exchange offer in a manner that it determines to constitute a material change,
Port Arthur Finance will promptly disclose such amendment in a manner
reasonably calculated to inform the holders of outstanding notes of such
amendment.
Without limiting the manner in which it may choose to make public
announcements of any delay in acceptance, extension, termination or amendment
of the exchange offer, Port Arthur Finance shall have no obligation to publish,
advertise, or otherwise communicate any such public announcement, other than by
making a timely release to a financial news service.
Conditions to the Exchange Offer
Despite any other term of the exchange offer, Port Arthur Finance will not be
required to accept for exchange, or exchange any exchange notes for, any
outstanding notes, and Port Arthur Finance may terminate the exchange offer as
provided in this prospectus before accepting any outstanding notes for exchange
if in its reasonable judgment:
. the exchange notes to be received will not be tradeable by the holder,
without restriction under the Securities Act, the Securities Exchange
Act of 1934 and without material restrictions under the blue sky or
securities laws of substantially all of the states of the United States;
. the exchange offer, or the making any exchange by a holder of
outstanding notes, would violate applicable law or any applicable
interpretation of the staff of the Commission; or
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. any action or proceeding has been instituted or threatened in any court
or by or before any governmental agency with respect to the exchange
offer that, in Port Arthur Finance's judgment, would reasonably be
expected to impair the ability of Port Arthur Finance to proceed with
the exchange offer.
In addition, Port Arthur Finance will not be obligated to accept for exchange
the outstanding notes of any holder that has not made to it
. the representations described under "--Purpose and Effect of the
Exchange Offer," "--Procedures for Tendering" and "Plan of
Distribution", and
. such other representations as may be reasonably necessary under
applicable Commission rules, regulations or interpretations to make
available to an appropriate form for registration of the exchange notes
under the Securities Act.
Port Arthur Finance expressly reserves the right, at any time or at various
times, to extend the period of time during which the exchange offer is open.
Consequently, it may delay acceptance of any outstanding notes by giving oral
or written notice of such extension to their holders. During any such
extensions, all outstanding notes previously tendered will remain subject to
the exchange offer, and Port Arthur Finance may accept them for exchange. Port
Arthur Finance will return any outstanding notes that it does not accept for
exchange for any reason without expense to their tendering holder as promptly
as practicable after the expiration or termination of the exchange offer.
Port Arthur Finance expressly reserves the right to amend or terminate the
exchange offer, and to reject for exchange any outstanding notes not previously
accepted for exchange, upon the occurrence of any of the conditions of the
exchange offer specified above. Port Arthur Finance will give oral or written
notice of any extension, amendment, non-acceptance or termination to the
holders of the outstanding notes as promptly as practicable. In the case of any
extension, such notice will be issued no later than 9:00 a.m., New York City
time, on the business day after the previously scheduled expiration date.
These conditions are for the sole benefit of Port Arthur Finance and Port
Arthur Finance may assert them regardless of the circumstances that may give
rise to them or waive them in whole or in part at any or at various times in
our sole discretion. If Port Arthur Finance fails at any time to exercise any
of the foregoing rights, this failure will not constitute a waiver of such
right. Each such right will be deemed an ongoing right that Port Arthur Finance
may assert at any time or at various times.
In addition, Port Arthur Finance will not accept for exchange any outstanding
notes tendered, and will not issue exchange notes in exchange for any such
outstanding notes, if at such time any stop order will be threatened or in
effect with respect to the registration statement of which this prospectus
constitutes a part or the qualification of the indenture under the Trust
Indenture Act of 1939.
Procedures for Tendering
Only a holder of outstanding notes may tender such outstanding notes in the
exchange offer. To tender in the exchange offer, a holder must:
. complete, sign and date the letter of transmittal, or a facsimile of the
letter of transmittal; have the signature on the letter of transmittal
guaranteed if the letter of transmittal so requires; and mail or deliver
such letter of transmittal or facsimile to the exchange agent prior to
the expiration date; or
. comply with DTC's Automated Tender Offer Program procedures described
below.
In addition, either:
. the exchange agent must receive outstanding notes along with the letter
of transmittal; or
. the exchange agent must receive, prior to the expiration date, a timely
confirmation of book-entry transfer of such outstanding notes into the
exchange agent's account at DTC according to the procedure for book-
entry transfer described below or a properly transmitted agent's
message; or
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. the holder must comply with the guaranteed delivery procedures described
below.
To be tendered effectively, the exchange agent must receive any physical
delivery of the letter of transmittal and other required documents at the
address set forth below under "--Exchange Agent" prior to the expiration date.
The tender by a holder that is not withdrawn prior to the expiration date
will constitute an agreement between such holder and Port Arthur Finance in
accordance with the terms and subject to the conditions set forth in this
prospectus and in the letter of transmittal.
The method of delivery of outstanding notes, the letter of transmittal and
all other required documents to the exchange agent is at the holder's election
and risk. Rather than mail these items, Port Arthur Finance recommends that
holders use an overnight or hand delivery service. In all cases, holders should
allow sufficient time to assure delivery to the exchange agent before the
expiration date. Holders should not send the letter of transmittal or
outstanding notes to Port Arthur Finance Holders may request their respective
brokers, dealers, commercial banks, trust companies or other nominees to effect
the above transactions for them.
Any beneficial owner whose outstanding notes are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee and who wishes
to tender should contact the registered holder promptly and instruct it to
tender on the owner's behalf. If such beneficial owner wishes to tender on its
own behalf, it must, prior to completing and executing the letter of
transmittal and delivering its outstanding notes; either:
. make appropriate arrangements to register ownership of the outstanding
notes in such owner's name; or
. obtain a properly completed bond power from the registered holder of
outstanding notes.
The transfer of registered ownership may take considerable time and may not
be completed prior to the expiration date.
Signatures on a letter of transmittal or a notice of withdrawal described
below must be guaranteed by a member firm of a registered national securities
exchange or of the National Association of Securities Dealers, Inc., a
commercial bank or trust company having an office or correspondent in the
United States or another "eligible guarantor institution" within the meaning of
Rule 17Ad-15 under the Exchange Act, unless the outstanding notes tendered
pursuant thereto are tendered:
. by a registered holder who has not competed the box entitled "Special
Issuance Instructions" or "Special Delivery Instructions" on the letter
of transmittal; or
. for the account of an eligible guarantor institution.
If the letter of transmittal is signed by a person other than the registered
holder of any outstanding notes listed on the outstanding notes, such
outstanding notes must be endorsed or accompanied by a properly completed bond
power. The bond power must be signed by the registered holder as the registered
holder's name appears on the outstanding notes and an eligible institution must
guarantee the signature on the bond power.
If the letter of transmittal or any outstanding notes or bond powers are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, such persons should so indicate when signing. Unless waived by us,
they should also submit evidence satisfactory to us of their authority to
deliver the letter of transmittal.
The exchange agent and DTC have confirmed that any financial institution that
is a participant in DTC's system may use DTC's Automated Tender Offer Program
to tender. Participants in the program may, instead of physically completing
and signing the letter of transmittal and delivering it to the exchange agent,
transmit their acceptance of the exchange offer electronically. They may do so
by causing DTC to transfer the outstanding
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notes to the exchange agent in accordance with its procedures for transfer. DTC
will then send an agent's message to the exchange agent. The term "agent's
message" means a message transmitted by DTC, received by the exchange agent and
forming part of the book-entry confirmation, to the effect that:
. DTC has received an express acknowledgment from a participant in its
Automated Tender Offer Program that is tendering outstanding notes that
are the subject of such book-entry confirmation;
. such participant has received and agrees to be bound by the terms of the
letter of transmittal, or, in the case of an agent's message relating to
guaranteed delivery, that such participant has received and agrees to be
bound by the applicable notice of guaranteed delivery; and
. the agreement may be enforced against such participant.
Port Arthur Finance will determine in its sole discretion all questions as to
the validity, form, eligibility, including time of receipt, acceptance of
tendered outstanding notes and withdrawal of tendered outstanding notes. Port
Arthur Finance's determination will be final and binding. Port Arthur Finance
reserves the absolute right to reject any outstanding notes not properly
tendered or any outstanding notes our acceptance of which would, in the opinion
of our counsel, be unlawful. Port Arthur Finance also reserves the right to
waive any defects, irregularities or conditions of tender as to particular
outstanding notes. Port Arthur Finance's interpretation of the terms and
conditions of the exchange offer, including the instructions in the letter of
transmittal, will be final and binding on all parties. Unless waived, any
defects or irregularities in connection with tenders of outstanding notes must
be cured within such time as Port Arthur Finance shall determine. Although Port
Arthur Finance intends to notify holders of defects or irregularities with
respect to tenders of outstanding notes, neither it, the exchange agent nor any
other person will incur any liability for failure to give such notification.
Tenders of outstanding notes will not be deemed made until such defects or
irregularities have been cured or waived. Any outstanding notes received by the
exchange agent that are not properly tendered and as to which the defects or
irregularities have not been cured or waived will be returned to the exchange
agent without cost to the tendering holder, unless otherwise provided in the
letter of transmittal, as soon as practicable following the expiration date.
In all cases, Port Arthur Finance will issue exchange notes for outstanding
notes that it has accepted for exchange under the exchange offer only after the
exchange agent timely receives:
. outstanding notes or a timely book-entry confirmation of such
outstanding notes into the exchange agent's account at DTC; and
. a properly completed and duly executed letter of transmittal and all
other required documents or a properly transmitted agent's message.
By signing the letter of transmittal, each tendering holder of outstanding
notes will represent to Port Arthur Finance that, among other things:
. any exchange notes that the holder receives will be acquired in the
ordinary course of its business;
. the holder has no arrangement or understanding with any person or entity
to participate in the distribution of the exchange notes;
. if the holder is not a broker-dealer, that it is not engaged in and does
not intend to engage in the distribution of the exchange notes;
. if the holder is a broker-dealer that will receive exchange notes for
its own account in exchange for outstanding notes that were acquired as
a result of market-making activities, that it will deliver a prospectus,
as required by law, in connection with any resale of such exchange
notes; and
. the holder is not an "affiliate," as defined in Rule 405 of the
Securities Act, of Port Arthur Finance or, if the holder is an
affiliate, it will comply with any applicable registration and
prospectus delivery requirements of the Securities Act.
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Book-Entry Transfer
The exchange agent will make a request to establish an account with respect
to the outstanding notes at DTC for purposes of the exchange offer promptly
after the date of this prospectus; and any financial institution participating
in DTC's system may make book-entry delivery of outstanding notes by causing
DTC to transfer such outstanding notes into the exchange agent's account at DTC
in accordance with DTC's procedures for transfer. Holders of outstanding notes
who are unable to deliver confirmation of the book-entry tender of their
outstanding notes into the exchange agent's account at DTC or all other
documents required by the letter of transmittal to the exchange agent on or
prior to the expiration date must tender their outstanding notes according to
the guaranteed delivery procedures described below.
Guaranteed Delivery Procedures
Holders wishing to tender their outstanding notes but whose outstanding notes
are not immediately available or who cannot deliver their outstanding notes,
the letter of transmittal or any other required documents to the exchange agent
or comply with the applicable procedures under DTC's Automated Tender Offer
Program prior to the expiration date may tender if:
. the tender is made through an eligible institution;
. prior to the expiration date, the exchange agent receives from such
eligible guarantor institution either a properly completed and duly
executed notice of guaranteed delivery, by facsimile transmission, mail
or hand delivery, or a properly transmitted agent's message and notice
of guaranteed delivery:
. setting forth the name and address of the holder, the registered
number(s) of such outstanding notes and the principal amount of
outstanding notes tendered;
. stating that the tender is being made thereby;
. guaranteeing that, within three (3) New York Stock Exchange
trading days after the expiration date, the letter of transmittal,
or facsimile of the letter of transmittal, together with the
outstanding notes or a book-entry confirmation, and any other
documents required by the letter of transmittal will be deposited
by the Eligible Institution with the exchange agent; and
. the exchange agent receives such properly completed and executed letter
of transmittal, or facsimile of the letter of transmittal, as well as
all tendered outstanding notes in proper form for transfer or a book-
entry confirmation, and all other documents required by the letter of
transmittal, within three (3) New York State Exchange trading days after
the expiration date.
Upon request to the exchange agent, a notice of guaranteed delivery will be
sent to holders who wish to tender their outstanding notes according to the
guaranteed delivery procedures set forth above.
Withdrawal of Tenders
Except as otherwise provided in this prospectus, holders of outstanding notes
may withdraw their tenders at any time prior to the expiration date.
For a withdrawal to be effective:
. the exchange agent must receive a written notice, which may be by
telegram, telex, facsimile transmission or letter, of withdrawal at one
of the addresses set forth below under "--Exchange Agent", or
. holders must comply with the appropriate procedures of DTC's Automated
Tender Offer Program system.
Any such notice of withdrawal must:
. specify the name of the person who tendered the outstanding notes to be
withdrawn
. identify the outstanding notes to be withdrawn, including the principal
amount of such outstanding notes; and
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. where certificates for outstanding notes have been transmitted, specify
the name in which such outstanding notes were registered, if different
from that of the withdrawing holder.
If certificates for outstanding notes have been delivered or otherwise
identified to the exchange agent, then, prior to the release of such
certificates, the withdrawing holder must also submit:
. the serial numbers of the particular certificates to be withdrawn; and
. a signed notice of withdrawal with signatures guaranteed by an eligible
institution unless such holder is an eligible institution.
If outstanding notes have been tendered pursuant to the procedure for book-
entry transfer described above, any notice of withdrawal must specify the name
and number of the account at DTC to be credited with the withdrawn outstanding
notes and otherwise comply with the procedures of such facility. Port Arthur
Finance will determine all questions as to the validity, form and eligibility,
including time of receipt, of such notices, and our determination shall be
final and binding on all parties. Port Arthur Finance will deem any outstanding
notes so withdrawn not to have validity tendered for exchange for purposes of
the exchange offer. Any outstanding notes that have been tendered for exchange
but that are not exchanged for any reason will be returned to their holder
without cost to the holder, or, in the case of outstanding notes tendered by
book-entry transfer into the exchange agent's account at DTC according to the
procedures described above, such outstanding notes will be credited to an
account maintained with DTC for outstanding notes, as soon as practicable after
withdrawal, rejection of tender or termination of the exchange offer. Properly
withdrawn outstanding notes may be retendered by following one of the
procedures described under "--Procedures for Tendering" above at any time on or
prior to the expiration date.
Exchange Agent
HSBC Bank USA has been appointed as exchange agent for the exchange offer.
You should direct questions and requests for assistance, requests for
additional copies of this prospectus or of the letter of transmittal and
requests for the notice of guaranteed delivery to the exchange agent addressed
as follows:
For Delivery by Registered or Certified Mail: For Overnight Delivery Only or
by Hand:
HSBC Bank USA HSBC Bank USA
140 Broadway--Level A 140 Broadway--Level A
New York, New York 10005-1180 New York, New York 10005-1180
By Facsimile Transmission, for eligible institutions only:
HSBC Bank USA
(212) 658-2292
Attn: Paulette Shaw
Delivery of the letter of transmittal to an address other than as set forth
above or transmission via facsimile other than as set forth above does not
constitute a valid delivery of such letter of transmittal.
Fees and Expenses
Port Arthur Finance will bear the expenses of soliciting tenders. The
principal solicitation is being made by mail; however, we may make additional
solicitation by telegraph, telephone or in person by our officers and regular
employees and those of our affiliates.
Port Arthur Finance has not retained any dealer-manager in connection with
the exchange offer and will not make any payments to broker-dealers or others
soliciting acceptances of the exchange offer. We will, however, pay the
exchange agent reasonable and customary fees for its services and reimburse it
for its related reasonable out-of-pocket expenses.
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Port Arthur Finance will pay the cash expenses to be incurred in connection
with the exchange offer. The expenses are estimated in the aggregate to be
approximately $ . They include:
. Commission registration fees;
. fees and expenses of the exchange agent and trustee;
. accounting and legal fees and printing costs; and
. related fees and expenses.
Port Arthur Finance will pay all transfer taxes, if any, applicable to the
exchange of outstanding notes under the exchange offer. The tendering holder,
however, will be required to pay any transfer taxes, whether imposed on the
registered holder or any other person, if:
. certificates representing outstanding notes for principal amounts not
tendered or accepted for exchange are to be delivered to, or are to be
issued in the name of, any person other than the registered holder of
outstanding notes tendered;
. tendered outstanding notes are registered in the name of any person
other than the person signing the letter of transmittal; or
. a transfer tax is imposed for any reason other than the exchange of
outstanding notes under the exchange offer.
If satisfactory evidence of payment of such taxes is not submitted with the
letter of transmittal, the amount of such transfer taxes will be billed to that
tendering holder.
Transfer Taxes
Holders who tender their outstanding notes for exchange will not be required
to pay any transfer taxes. However, holders who instruct Port Arthur Finance to
register exchange notes in the name of, or request that outstanding notes not
tendered or not accepted in the exchange offer be returned to, a person other
than the registered tendering holder will be required to pay any applicable
transfer tax.
Consequences of Failure to Exchange
Holders of outstanding notes who do not exchange their outstanding notes for
exchange notes under the exchange offer will remain subject to the restrictions
on transfer of such outstanding notes:
. as set forth in the legend printed on the notes as a consequence of the
issuance of the outstanding notes pursuant to the exemptions from, or in
transactions not subject to, the registration requirements of the
Securities Act and applicable state securities laws; and
. otherwise set forth in the offering memorandum distributed in connection
with the private offering of the outstanding notes.
In general, you may not offer or sell the outstanding notes unless they are
registered under the Securities Act, or if the offer or sale is exempt from
registration under the Securities Act and applicable state securities laws.
Except as required by the registration rights agreement, we do not intend to
register resales of the outstanding notes under the Securities Act. Based on
interpretations of the Commission staff, exchange notes issued pursuant to the
exchange offer may be offered for resale, resold or otherwise transferred by
their holders, other than any such holder that is our "affiliate" within the
meaning of Rule 405 under the Securities Act, without compliance with the
registration and prospectus delivery provisions of the Securities Act, provided
that the holders acquired the exchange notes in the ordinary course of the
holders' business and the holders have no arrangement or understanding with
respect to the distribution of the exchange notes to be acquired in the
exchange offer. Any holder who tenders in the exchange offer for the purpose of
participating in a distribution of the exchange notes:
. could not rely on the applicable interpretations of the Commission; and
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. must comply with the registration and prospectus delivery requirements
of the Securities Act in connection with a secondary resale transaction.
Accounting Treatment
Port Arthur Finance will record the exchange notes in our accounting records
at the same carrying value as the outstanding notes, which is the aggregate
principal amount, as reflected in our accounting records on the date of
exchange. Accordingly, Port Arthur Finance will not recognize any gain or loss
for accounting purposes in connection with the exchange offer. We will record
the expenses of the exchange offer as incurred.
Other
Participation in the exchange offer is voluntary, and you should carefully
consider whether to accept. You are urged to consult your financial and tax
advisors in making your own decision on what action to take.
Port Arthur Finance may in the future seek to acquire untendered outstanding
notes in open market or privately negotiated transactions, through subsequent
exchange offers or otherwise. Port Arthur Finance has no present plans to
acquire any outstanding notes that are not tendered in the exchange offer or to
file a registration statement to permit resales of any untendered outstanding
notes.
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DESCRIPTION OF THE NOTES
General
The outstanding notes were issued and the exchange notes will be issued under
an indenture, dated as of August 19, 1999, among us, Sabine River, Neches
River, HSBC Bank USA, as indenture trustee, and Bankers Trust Company, as
collateral trustee. The indenture contains the full legal text of the matters
described in this section. A copy of the indenture has been filed as an exhibit
to the registration statement of which this prospectus is a part. Upon the
issuance of the exchange notes, or the effectiveness of a shelf registration
statement, the indenture will be subject to and governed by the Trust Indenture
Act of 1939. The terms of the notes include those stated in the indenture and
those made part of the indenture by reference to the Trust Indenture Act.
The following description is a summary of the material provisions of the
notes and the indenture. It does not describe every aspect of the notes. We
urge you to read the notes and the indenture because they, and not this
description, define your rights as holder of the notes.
Principal, Maturity and Interest
We have issued $255 million in principal amount of 12.50% senior secured
outstanding notes due 2009. The notes will mature on January 15, 2009.
The notes bear interest at an annual rate of 12.50%. Interest on the notes
will be paid semiannually on January 15 and July 15 of each year, commencing
January 15, 2000, to holders of record on each January 1 and July 1 preceding
such interest payment dates. Interest on the notes will be computed on the
basis of a 360-day year of twelve 30-day months. The interest rate on the notes
may increase under circumstances described under "Description of Our Principal
Financing Documents--Registration Rights Agreement."
Installments of principal on the notes are payable as follows:
<TABLE>
<CAPTION>
Percentage of Principal
Payment Date Amount Payable
------------ -----------------------
<S> <C>
July 15, 2002.................. 1.70%
January 15, 2003............... 1.70%
July 15, 2003.................. 4.10%
January 15, 2004............... 4.10%
July 15, 2004.................. 6.00%
January 15, 2005............... 6.00%
July 15, 2005.................. 9.10%
January 15, 2006............... 9.10%
July 15, 2006.................. 9.10%
January 15, 2007............... 9.10%
July 15, 2007.................. 7.90%
January 15, 2008............... 7.90%
July 15, 2008.................. 12.10%
January 15, 2009............... 12.10%
</TABLE>
The Guarantees
Port Arthur Coker Company, Sabine River and Neches River have unconditionally
jointly and severally guaranteed to each note holder:
. the due and punctual payment of principal and interest on the notes;
. the performance by Port Arthur Finance of its obligations under the
indenture and other financing documents; and
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. that its guarantor obligations will be as if it were a principal debtor
and obligor and not merely a surety.
The guarantees will be endorsed on and attached to the notes.
Nonrecourse Obligations
The obligations to pay principal of, premium, if any, and interest on the
notes are the obligations of only Port Arthur Finance, Port Arthur Coker
Company, Sabine River and Neches River. None of our other owners, affiliates,
employees, officers, directors or any other person or entity have guaranteed
the notes or have any obligation to make any payments on the notes.
Security
The notes are secured by, among other things:
. the delayed coker, the vacuum gas oil hydrocracker and the sulfur
recovery complex;
. our leasehold interest in our heavy oil processing facility sites, the
crude unit, vacuum tower and the naphtha and two distillate
hydrotreaters;
. all of our interests in crude oil and intermediate and refined products;
. all our accounts, except for an operating account for short term
expenses;
. the partnership interests in Port Arthur Coker Company;
. the capital stock of Port Arthur Finance;
. all our rights in our equity contribution agreements;
. all rights in all our major contracts, including our long term crude oil
supply agreement with P.M.I. Comercio Internacional, our construction
contract with Foster Wheeler USA and our services and supply agreement
and product purchase agreement with Clark Refining & Marketing; and
. to the extent permitted by law, all our rights in governmental permits
and licenses.
The collateral securing the notes is shared, on an equal and ratable basis,
with the other senior lenders, any replacement senior lenders and other secured
parties and is described in greater detail under "Description of Our Principal
Financing Documents--Common Security Agreement--Scope and Nature of the
Security Interest."
Ranking of the Notes
The notes:
. are senior secured indebtedness of Port Arthur Finance;
. rank equivalent in right of payment to all other senior indebtedness of
Port Arthur Finance, Port Arthur Coker Company, Sabine River and Neches
River and our payment obligations under the guaranty insurance policy;
and
. rank senior in right of payment to all existing and future subordinate
indebtedness of Port Arthur Finance, Port Arthur Coker Company, Sabine
River and Neches River.
Redemption at Our Option
We may choose to redeem some or all of the notes at any time, without the
consent of noteholders, at a redemption price equal to 100% of the outstanding
unpaid principal amount of notes being redeemed plus accrued and unpaid
interest, if any, up to but excluding the applicable redemption date plus a
make-whole
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premium. The make-whole premium will be equal to the excess, if positive, of
(1) the present value of all interest and unpaid principal payments scheduled
to be made on the notes, at a discount rate equal to 75 basis points over the
yield to maturity on the U.S. treasury instruments with a maturity as close as
practicable to the remaining average life of the notes, over (2) the unpaid
principal amount of the notes to be redeemed.
Notice of redemption will be mailed by the indenture trustee to each
noteholder at that noteholder's address of record not less than 30 days nor
more than 60 days prior to the date of redemption. On the date of redemption,
the redemption price will become due and payable on each note to be redeemed
and interest thereon will cease to accrue on and after such date.
Mandatory Redemption
If we receive specified mandatory payment proceeds, which includes insurance
proceeds from casualty events, condemnation compensation and late payments to
the extent not needed to pay interest on the senior debt and buy-down payments
from Foster Wheeler USA, we are required to redeem all our outstanding senior
debt on an equal and ratable basis. The redemption price for the notes will be
equal to 100% of the unpaid principal amount of notes being redeemed, plus
accrued but unpaid interest, if any, on the notes being redeemed, up to but
excluding the date of redemption. The mandatory redemption provisions governing
the notes are described in greater detail under "Description of Our Principal
Financing Documents--Common Security Agreement--Mandatory Prepayments."
Repurchases by Us
Subject to the terms of the common security agreement, we or our respective
affiliates may at any time purchase the notes in the open market or otherwise
at any price agreed upon between us and the applicable holders. Any note so
purchased by us must be surrendered to the indenture trustee for cancellation
and may not be re-issued or resold.
Transfer and Exchange
A noteholder may transfer or exchange notes only in accordance with and
subject to the restrictions on transfer contained in the indenture.
Satisfaction and Discharge
Under specified circumstances, we can deposit funds with the indenture
trustee sufficient to pay and discharge the indebtedness on any outstanding
notes. In that case, we would cease to have any obligations under the
indenture.
Indenture Subject to Common Security Agreement
The indenture trustee has entered into the common security agreement and
other financing documents on behalf of all noteholders from time to time. All
rights, powers and remedies available to the indenture trustee and the
noteholders and all future noteholders, under the common security agreement and
the other financing documents are in addition to those under the indenture. In
the event of any conflict or inconsistency between the terms and provisions of
the indenture and the common security agreement, the terms of the common
security agreement govern and control.
Intercreditor Arrangements
In the event that any consent, approval, waiver or other direction of the
senior lenders is sought by the indenture trustee or the collateral trustee
pursuant to the common security agreement and the matter with respect to which
such consent, approval, waiver or direction as sought is a matter that the
indenture trustee is entitled to vote on under the common security agreement as
representative of the noteholders, the indenture trustee, promptly upon the
receipt of notice from the collateral trustee describing the action to be
voted, will be
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obligated to promptly notify the holders and duly convene a meeting of
holders, whose instructions may be conveyed by written consent, to canvass the
holders as to votes to be cast by the indenture trustee regarding the matter.
If no instructions are so issued, the indenture trustee will be obligated to
abstain from voting.
Modification, Amendment and Waiver
The indenture and the notes may be modified without the consent of any
noteholder, including, among other things:
. to evidence the succession of another person to Port Arthur Finance, Port
Arthur Coker Company, Sabine River or Neches River;
. to add to the covenants or events of default for the benefit of the
noteholders;
. to comply with any applicable rules or regulations of any securities
exchange on which the notes may be listed;
. to cure any ambiguity in the indenture or in the notes, to correct or
supplement any provision in the indenture, the notes or any other
financing document which may be defective or inconsistent with any other
provision of the indenture, the notes or any other financing document, or
to make any other provisions with respect to matters or questions arising
under the indenture or the notes, provided that any such action referred
to in this clause does not adversely affect the interests of the
noteholders in any material respect;
. to evidence and provide for the acceptance of appointment by a successor
indenture trustee with respect to the notes;
. to reflect the incurrence of permitted indebtedness under the common
security agreement and the granting of permitted liens pursuant to the
common security agreement; and
. to take any other action which may be taken without the consent of the
noteholders under the financing documents.
Further Issues and Additional Securities
From time to time we may, without notice to or the consent of the holders of
the notes, create and issue further notes ranking equally and ratably with the
notes in all respects, or in all respects except for the payment of interest
accruing prior to the issue date of such further notes or except for the first
payment of interest following the issue date of such further notes, and so
that such further notes will be consolidated and form a single series with the
notes and will have the same terms as to status, redemption or otherwise as
the notes. In addition, we may issue additional debt securities on terms
agreed by us and the underwriters of those securities. In each case described
above we may issue the further notes or additional debt securities pursuant to
a supplemental indenture. The issuance and application of the proceeds of any
additional notes or other securities will be subject to the requirements
applicable to additional senior debt or replacement senior debt in the common
security agreement, described in "Description of Our Principal Financing
Documents--Common Security Agreement--Additional Senior Debt" and "--
Replacement Senior Debt."
Notices and Reports
We are required to give notice to the indenture trustee of any event which
requires that notice be given to the noteholders, in sufficient time for the
indenture trustee to provide such notice to the noteholders in the manner
provided by the indenture. Also, the common security agreement provides that
upon request of a beneficial owner, we will provide directly to such
beneficial owner any financial information regarding us that we are required
to provide to the indenture trustee pursuant to the indenture or the common
security agreement.
The indenture trustee will transmit to noteholders such information,
documents and reports, and their summaries, concerning the indenture trustee
and its actions under the common security agreement as may be required and at
the times and in the manner provided in the common security agreement.
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All notices regarding the notes will be deemed to have been sufficiently
given upon the mailing by first-class mail, postage prepaid, of such notices to
each holder at the address of such holder as it appears in the security
register, in each case not earlier than the earliest date and not later than
the latest date prescribed in the indenture for the giving of such notice. Any
notice so mailed will be deemed to have been given on the date of such mailing.
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DESCRIPTION OF OUR PRINCIPAL FINANCING DOCUMENTS
The following is a summary of the material provisions of our principal
financing agreements and is not considered to be a full statement of the terms
of these agreements. A copy of each of these agreements has been filed as an
exhibit to the registration statement of which this prospectus is a part.
Unless otherwise stated, any reference in this prospectus to any agreement
means such agreement and all schedules, exhibits and attachments to such
agreements, as amended, supplemented or otherwise modified in effect as of the
date hereof. Capitalized terms used but not defined in this section under the
caption "Definitions for Our Financing Documents" have the respective meanings
given to them in the relevant documents. Unless otherwise noted, all financing
documents are governed by and construed in accordance with the laws of the
State of New York.
Common Security Agreement
We, along with Sabine River and Neches River, entered into a common security
agreement, dated as of August 19, 1999, with the collateral trustee, the bank
lenders administrative agent, the indenture trustee, the oil payment insurers
administrative agent and the depositary bank. The common security agreement
contains, among other things, common covenants, representations and
warranties, events of default and remedies applicable to all our senior debt,
including the notes, any loans made under our bank credit facilities and any
reimbursement obligations to Winterthur relating to Winterthur's oil payment
guaranty insurance policy.
Scope and Nature of the Security Interests
All senior lenders rank equally with respect to the common security package.
The oil payment insurers generally rank equally with respect to the common
security package as well. All secured parties share equally and ratably in the
common security package as calculated on the basis of the amounts outstanding
from time to time under each senior loan or the oil payment guaranty insurance
policy described in "--Oil Payment Guaranty Insurance Policy" below, as the
case may be.
The principal elements of the common security package the secured parties
include:
. all our real property interests and all improvements made on our
property, including our interests under the ground lease and the facility
and site lease and any fixtures on the coker project property;
. the 1% general partnership interest in Port Arthur Coker Company held by
Sabine River;
. the 99% limited partnership in Port Arthur Coker Company held by Neches
River;
. all 100% of the capital stock of Port Arthur Finance held by Port Arthur
Coker Company;
. all our rights in our equity contribution agreements;
. all our interests in any of the secured accounts at any time;
. all our interests under all project documents, including any rights we
may eventually have under any spot contracts or sales agreements for the
purchase of crude oil;
. all insurance policies issued to Port Arthur Coker Company and proceeds
we may receive from them;
. all our current and future ownership interests in any machinery,
equipment, intellectual property to the extent permitted by the
underlying contracts and other personal property;
. all our interest in any crude oil the title of which has passed to us,
all intermediate oil products produced throughout the refining process
and all refined products and any amounts receivable as a result of the
sale of any of these materials;
. all our interests in any permitted hedging instruments;
. all intercompany loans from Port Arthur Finance to Port Arthur Coker
Company, including the rights of Port Arthur Coker Company to receive
funds and the right of Port Arthur Finance to be repaid; and
. to the extent permitted by law, all our rights in governmental permits
and licenses.
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The secured parties that share equally in the common security package
include:
. the indenture trustee, on behalf of the noteholders;
. lenders under our bank credit facilities and their administrative agents;
. oil payment insurers and their administrative agent; and
. holders of our Additional Senior Debt or Replacement Senior Debt as
described under "--Additional Senior Debt" or "--Replacement Senior Debt"
below.
We, Sabine River and Neches River are required to take all actions necessary,
upon the request of the collateral trustee, to record any mortgage and perfect
any security interests created under the common security agreement. While the
common security agreement is in effect, none of the security interests will be
released unless we obtain the prior consent of all secured parties.
Account Structure
At our direction the collateral trustee has established and will maintain the
following secured accounts at Bankers Trust Company, as the depositary bank in
New York City:
. the Bank Loan Drawdown and Equity Funding Account, into which we are
required to deposit all funds borrowed under any senior loan, other than
proceeds from the issuance of the outstanding notes, along with the
capital contributions by both Blackstone and Occidental;
. the Bond Proceeds Account, into which we deposited the net proceeds from
the issuance of the outstanding notes;
. the Project Revenue Account, into which, among other funds:
. we will deposit, after substantial reliability, all funds in the Bank
Loan Drawdown and Equity Funding Account and the Bond Proceeds
Account, other than any amount we deposit into the Contingency
Reserve Account;
. we will cause each purchaser of our products to make payments
directly;
. we will cause persons making payments under the several project
documents to deposit such payments directly; and
. we will cause purchasers of any of our real or personal property to
deposit such payments directly;
. the PMI Premium Reserve Account, into which we are required to deposit an
amount equal to the quarterly surplus calculated in any quarter and which
we are then required to pay as a premium in the succeeding quarters;
. the Principal & Interest Accrual Account, into which we are required to
deposit funds available in the Project Revenue Account equal to (1) the
amount of principal and interest for senior debt due on the next Payment
Date as described under "--Secured Construction and Term Loan Agreement"
below and (2) on each of the last three or, in specified circumstances,
four Payment Dates, a pro rata share of the aggregate principal amount
then outstanding of the Tranche B loans, for further deposit into the
Tranche B Amortization Account, described below;
. the Tranche B Amortization Account, into which we are required to deposit
the amounts described in clause (2) under the description of the
Principal & Interest Accrual Amount above;
. the Tax Reserve Account, into which we are required to deposit an amount
sufficient to cover our estimated property taxes and also the estimated
share of the income and/or franchise taxes of Sabine River and/or Neches
River or that Sabine River and/or Neches River are required to pay Clark
Refining Holdings under the tax sharing agreement, in either case, in
respect of their allocable share of our taxable income and that are
expected to become due and payable on or before the next two Payment
Dates;
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. the Major Maintenance Account, into which we are required to deposit on
each Payment Date, to the extent that cash is available, an amount equal
to one-eighth, or at our option up to one-sixth, of the estimated major
maintenance expenses that we expect to incur in connection with our next
scheduled maintenance shutdown;
. the P.M.I. Surplus Reserve Account, into which we are required to deposit
and retain funds, to the extent that cash is available, in an amount
equal to any quarterly surpluses that we accrue pursuant to the coker
gross margin support mechanism under our long term crude oil supply
agreement with P.M.I. Comercio Internacional;
. the Debt Service Reserve Account, into which we are required to deposit
and retain funds in an amount that, together with the amount available
under the debt service reserve insurance guarantee described in
"Description of Our Principal Financing Documents--Debt Service Reserve
Insurance Guarantee," equals the aggregate senior debt obligations due
and payable on the immediately succeeding Payment Date;
. the Casualty and Insurance Account, into which we are required to direct
insurers to pay directly any insurance proceeds other than insurance
proceeds resulting from a catastrophic casualty;
. the Catastrophic Casualty Account, into which we are required to direct
insurers to pay directly any insurance proceeds resulting from a
catastrophic casualty;
. the Mandatory Prepayments Account, into which we or the collateral
trustee will deposit sums required to be used for mandatory prepayments;
. the Contingency Reserve Account, into which we may deposit, after we
achieve final completion, any amounts relating to unused budget
contingencies that we may put toward unbudgeted repairs, maintenance,
mandatory capital expenditures or the funding of the Debt Service Reserve
Account; and
. the Distribution Account, into which we are required to deposit any
excess funds that remain after the cash flow is applied in accordance
with the cash flow waterfall described under "--Withdrawals from Accounts
Pre-Default" below.
Also, we may maintain in an unsecured operating account up to 30 days' of our
operating expenses.
Withdrawals from Accounts Pre-Default.
Unless a Default described in "--Remedies" below has occurred and is
continuing, we have the right to direct the collateral trustee to withdraw
funds from the Bank Loan Drawdown and Equity Funding Account and the Bond
Proceeds Account or the Project Revenue Account and apply such funds in the
following order of priority:
First, (1) to pay our operating expenses, (2) to transfer funds into the
operating account in an amount equal to 30 days of our estimated operating
expenses, other than our operating expenses relating to the purchase of
crude oil, as certified by us and (3) thereafter, to transfer funds into
the PMI Premium Reserve Account in an amount equal to the quarterly surplus
received by us in any quarter.
Second, to pay reimbursement obligations described in "Description of Our
Principal Financing Documents--Guaranty Insurance Policy and Reimbursement
Agreement" below then due and payable by us;
Third, to pay senior debt obligations then due and payable by us, other
than the prepayments and repayments described in the tenth priority
position below;
Fourth, to transfer funds to the Principal & Interest Accrual Account in
an amount equal to (1) all senior debt obligations to become due prior to
and including the immediately succeeding Payment Date, less any balance
already in the Principal & Interest Accrual Account and (2) on each of the
last three or, in specified circumstances, four Payment Dates, a pro rata
share of the aggregate principal amount then outstanding of the Tranche B
loans, in the case of clause (2) for further deposit into the Tranche B
Amortization Account;
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Fifth, (1) to transfer funds to the Tax Reserve Account in an amount
equal to the Projected Tax Reserve Amount, less the balance already in the
Tax Reserve Account and (2) to pay a monitoring fee not exceeding $1
million in the aggregate in any calendar year to Blackstone, Clark Refining
& Marketing or any of their designated affiliates;
Sixth, to transfer funds to the Major Maintenance Account in an amount
not less than the minimum major maintenance reserve payment due on the
immediately succeeding Payment Date and not exceeding the maximum major
maintenance reserve payment with respect to such Payment Date;
Seventh, following (1) the incurrence of Additional Senior Debt or (2)
the termination or reduction of the debt service reserve insurance
guarantee, to transfer funds to the Debt Service Reserve Account to the
extent of any debt service reserve shortfall resulting from such incurrence
of Additional Senior Debt, in the case of (1), or any other event or
circumstance, in the case of (2);
Eighth, to transfer funds to the P.M.I. Surplus Reserve Account in an
amount equal to the amount, if any, by which the P.M.I. surplus under the
long term crude oil supply agreement exceeds the balance in the P.M.I.
Surplus Reserve Account, up to an amount not exceeding the net total
positive price adjustment we have received under the long term crude oil
supply agreement up to a maximum amount of $75 million, with the maximum
amount reduced to $50 million upon payment in full of all our construction
and term loans;
Ninth, to pay interest in respect of any amounts we have drawn down under
the debt service reserve insurance guarantee and, on the sixth Payment Date
and each subsequent Payment Date until the aggregate principal amount
available under the debt service reserve insurance guarantee has been
reduced to zero, to transfer $12 million to the Debt Service Reserve
Account, up to the amount of required reserve;
Tenth, after start-up, to prepay the construction and term loans, repay
any principal amounts drawn down under the debt service reserve insurance
guarantee and fund the Debt Service Reserve Account from excess cash flow
as described in "--Mandatory Prepayments--Prepayments of Bank Senior Debt"
and "--Debt Service Reserve Account" below.
Eleventh, after final completion, as defined in the construction
contract, to make Restricted Payments as described in "--Restricted
Payments" below.
In any event, withdrawals from the Project Revenue Account for any purpose
other than those described under "First" above will only be permitted if and to
the extent that the funds then on deposit in the Project Revenue Account exceed
the aggregate amount of all outstanding invoices in respect of our payment
obligations under the long term crude oil supply agreement.
Withdrawals from Accounts During the Continuance of a Default.
If a Default has occurred and is continuing, the senior lender(s) may notify
the collateral trustee that the collateral trustee will no longer accept
instructions from us for the investment, withdrawal or transfer of funds or
investments in the secured accounts. The depositary bank will thereafter accept
instructions for the investment, withdrawal or transfer of funds or investments
in these secured accounts solely from the collateral trustee or other person(s)
designated by the collateral trustee. The collateral trustee will invest
project funds only in Authorized Investments. The collateral trustee will give
the depositary bank prompt notice of these circumstances.
Following the receipt by the collateral trustee of such notice from the
senior lender(s) declaring a Default, and until such time as a cessation notice
has been given by any senior lender that the Default has been cured, or an
Enforcement Action is taken by the senior lenders the collateral trustee will
exercise its rights to instruct the depositary bank in a manner that causes
available funds in the accounts to be applied in the order of priority set
forth in the pre-Default waterfall described above, except that (1) no funds
will be credited to the Distribution Account and (2) any reimbursement
obligations that remain unpaid after the expiration of 30 days following the
giving of a Priority Termination Notice as described in "Description of Our
Principal Financing Documents--Guaranty Insurance Policy and Reimbursement
Agreement" below will rank equally and ratably
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in right of payment with the senior debt obligations then due and payable.
Funds not distributed pursuant to these provisions or the pre-Default
waterfall described above will remain in the Project Revenue Account. As an
exception to the foregoing, immediately before the expiration of the 30-day
period referred to above, the collateral trustee will apply any funds on
deposit in the Project Revenue Account, less any amounts earmarked to pay
outstanding invoices for purchases of crude oil or our other operating
expenses in the ordinary course of business, to the repayment of outstanding
reimbursement obligations.
Upon receipt by the collateral trustee of a cessation notice with respect to
a Default that is continuing, the collateral trustee will immediately notify
the depositary bank, with a copy to us, directing the depositary bank once
again to accept our directions, and the collateral trustee and the depositary
bank will again accept our directions in respect of investment, withdrawal and
transfer of funds in the secured accounts.
Debt Service Reserve Account
On each semiannual Payment Date we are required to deposit cash from the
following sources into the Debt Service Reserve Account up to the aggregate
amount of principal and interest due on the senior debt on the next Payment
Date:
. in accordance with the seventh and ninth priority positions in "--
Withdrawal from Accounts Pre-Default" above;
. after the repayment of any principal amounts outstanding under the debt
service reserve insurance guarantee, from 25% of the cash available at
the tenth priority position in "--Withdrawal from Accounts Pre-Default"
above that would otherwise have been applied to repay such principal
amounts in accordance with the financing documents; and
. after the repayment of all construction and term loans, from 75% of the
cash available at the tenth priority position in "--Withdrawal from
Accounts Pre-Default" above that would otherwise have been applied to
repay such construction and term loans in accordance with the financing
documents.
The balance in the Debt Service Reserve Account at any time of determination
will be deemed to be the aggregate of:
. the amount of cash then on deposit in the Debt Service Reserve Account;
. the market value of any Authorized Investments then on deposit in the
Debt Service Reserve Account; and
. the amount available under the debt service reserve insurance guarantee.
If no Default has occurred and is continuing, we may direct the collateral
trustee to apply the funds in the Debt Service Reserve Account at any time to
pay senior debt obligations, and at any time on or after a Priority
Termination Date, oil payment reimbursement obligations, then due and payable
on the date of withdrawal or within five business days, but only to the extent
that there are insufficient funds in the Principal & Interest Accrual Account
to make the required debt service payment. Post-default withdrawals will be
made in accordance with "--Withdrawals from Accounts Post-Default" above.
Conditions Precedent
The obligation of each senior lender to make any future disbursement of a
senior loan will be subject to (1) satisfaction or waiver by it of each of the
conditions precedent set forth in such senior loan agreement and (2) specified
conditions set forth in the common security agreement, including the
following:
. no Event of Default or Potential Default as described in "--Event of
Default" below;
. the representations and warranties are true and correct in all material
respects as of the date of such borrowing;
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. no notice of abandonment has been delivered to us;
. we must not have received a notice from the collateral trustee, delivered
at the instruction of Majority Lenders, that Majority Lenders have
determined in their reasonable judgment that a material adverse change
has occurred in (1) the engineering, construction, development, operation
or performance of our coker project or (2) the financial condition of any
of us, Clark Refining & Marketing, Air Products, P.M.I. Comercio
Internacional, PEMEX, Foster Wheeler USA or Foster Wheeler Corporation
that is reasonably expected to have a material adverse effect on our
financial condition or the engineering, construction, development,
operation or performance of our coker project; provided that the
occurrence of any change in general economic conditions or market prices
for crude oil or refined products or any downgrade in the senior
unsecured long-term debt rating of Clark Refining & Marketing by Moody's
or Standard & Poor's, or both, if by not more than one rating category,
will not be deemed to constitute such a material adverse change;
. we must have received an equal and ratable capital contribution from
Blackstone and Occidental; and
. we may be required to hedge a substantial portion of our floating rate
exposure under our secured construction and term loan facility.
Restricted Payments
We may not make any partnership distribution, which we refer to as
"Restricted Payments," unless each of the following conditions has been met:
. final completion has occurred;
. immediately prior and after giving effect to such Restricted Payment, no
Event of Default or Potential Default or full or partial downtime has
occurred and is continuing;
. immediately prior and after giving effect to such Restricted Payment, the
Debt Service Reserve Account, the Principal & Interest Accrual Account,
the Tax Reserve Account, the P.M.I. Surplus Reserve Account, if required,
the Major Maintenance Account and the PMI Premium Reserve Account, if
required, will be fully funded and all project expenses and mandatory
capital expenditures that have become due and payable have been paid;
. both the projected Debt Service Coverage Ratio for the projected twelve-
month period beginning on the first day after such Restricted Payment is
made and the historical Debt Service Coverage Ratio for the historical
twelve-month period ended on the date such Restricted Payment is made are
not less than 1.6:1.0 or, if the notes then have an investment grade
rating by both Standard & Poor's and Moody's, 1.35:1.0;
. such Restricted Payment is made within 30 days immediately following a
Payment Date;
. no insolvency event with respect to Clark Refining & Marketing has
occurred and is continuing; and
. we will give the collateral trustee not less than five business days
prior notice of the proposed date of any Restricted Payment to be made,
attached with our certificate that the conditions to such Restricted
Payment have been satisfied, together with information and computations
demonstrating compliance with such conditions.
The common security agreement restricts our ability to pay fees or make
other payments to our affiliates. We may, however, make partnership
distributions to Sabine River and Neches River (1) in an aggregate amount not
to exceed $100,000 in each year in order to permit our partners to pay
directors' fees, accounting expenses and other administrative expenses or (2)
of the amounts in the Tax Reserve Account from time to time in order to permit
Sabine River and Neches River to pay their income taxes or the amounts they
are required to pay Clark Holdings under the tax sharing agreement.
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Representations and Warranties
When we entered into the common security agreement, each of us, Sabine River
and Neches River severally made customary representations and warranties to
the collateral trustee, each Applicable Agent, the secured parties and the
depositary bank, including those with respect to:
. organization, ownership and power and authority to own property and
conduct business;
. power and authority to execute, deliver, incur and perform our
obligations under and enforceability of the transaction documents;
. governmental consents and approvals for the coker project and the
transaction documents;
. absence of facts that could have a Material Adverse Effect and have not
been disclosed in writing to the senior lenders;
. no conflicts with any other agreement;
. compliance with laws, receipt of all governmental consents and approvals
for our coker project and the transaction documents, and absence of
litigation;
. title to property and validity of security interests;
. ranking of senior debt;
. no Default;
. affiliate transactions on arm's-length terms;
. year 2000 compliance;
. environmental laws;
. no force majeure event;
. separate identity from the Clark Entities;
. adequacy of services provided under project documents for our coker
project; and
. sole purpose of Port Arthur Finance.
Covenants
Each of us is bound by, among other things, the following covenants and
agreements:
Maintenance of Existence. We will do all things necessary to maintain:
. our due organization, valid existence and good standing; and
. the power and authority necessary to own our properties and to carry on
the business of our coker project.
No Modification. We will not take any action to amend or modify our
constitutive or governing documents in any respect unless:
. a copy of the modification has been delivered to the collateral trustee
reasonably in advance of the effective date thereof, along with a
certificate of a responsible officer certifying that such amendment or
waiver could not reasonably be expected to have a Material Adverse
Effect; or
. we have obtained the prior consent of Supermajority Lenders, or, in
specified circumstances, of Supermajority Secured Parties.
Business. We will conduct no business or activity other than the business of
our coker project.
Accounting and Cost Control Systems. We will maintain, or cause to be
maintained, our own management information and cost accounting systems for our
coker project at all times in accordance with
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prudent industry practice and separate and apart from all management
information and cost accounting systems of any of the Clark Entities, and will
employ independent auditors of recognized national standing to audit annually
our financial statements.
Access. We will grant the collateral trustee, each bank senior lender, oil
payment insurers administrative agent and the indenture trustee or their
designees, complete access to our books and records, quality control and
performance test data, all other data relating to our coker project and
construction progress of our coker project and an opportunity to discuss
accounting matters with our independent auditors. Each of the independent
consultants, bank senior lenders, the collateral trustee, the oil payment
insurers administrative agent and the indenture trustee will also have the
right to monitor, witness and appraise the construction, testing and
operations of our coker project. We will offer and cause our officers,
employees, agents and contractors to offer all reasonable assistance to the
persons making any such visit.
Environmental Audits. If the collateral trustee, any bank senior lender, the
oil payment insurers administrative agent or the indenture trustee or any of
their designees reasonably believes that a release, threat of release or
violation of any environmental law may have occurred, or if an Event of
Default or Potential Default has occurred, we will grant access to and assist
any environmental consultants to conduct any requested environmental
compliance or contamination audits in their sole discretion.
Preservation of Assets.
. We will maintain our assets in good repair and will make such repairs
and replacements as are required in accordance with prudent industry
practice.
. We will not sell, assign, lease, transfer or otherwise dispose of any
project property without the prior consent of Supermajority Lenders or,
in specified circumstances, consent of Supermajority Secured Parties,
except for:
. dispositions of project production other than dispositions prohibited
by the terms of the "Project Production" covenant set forth below;
. dispositions of project property that has become obsolete or
redundant;
. dispositions made in the ordinary course of our business;
. dispositions of project property up to an aggregate value of $50
million in the form of a sale/lease back transaction as part of a
tax-exempt bond financing under the laws of the State of Texas to
replace senior debt, which disposition is approved by the bank
lenders administrative agent, or
. dispositions of project property the net proceeds of which are used
within 90 days of such disposition to replace such project property.
Taxes. We will file or cause to be filed all returns required to be filed by
us and we will pay and discharge, before delinquent, all taxes imposed on us
or our property, including interest and penalties.
Compliance with Law. We will comply and cause our contractors to comply with
all applicable laws, rules, regulations and orders of governmental
authorities.
Maintenance of Approvals for Agreements. We will maintain or cause to be
maintained all third-party authorizations that are necessary for:
. the execution, delivery and performance by us of each transaction
document to which we are a party;
. the incurrence or guarantee of the senior debt obligations, as the case
may be; and
. the performance of our obligations under the financing documents.
Maintenance of Approvals for Coker Project. We will maintain or cause to be
maintained all:
. third-party authorizations, including authorization, consent and
approval by government authority;
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. easements, leases, rights-of-way, auxiliary rights and other real
property rights; and
. licenses and other rights to use all technology necessary to develop,
construct, operate, maintain and finance the coker project.
Maintenance of Supply. We will maintain supplies of, or contracts providing
for supplies of, hydrogen, electricity, steam, natural gas and other
feedstocks and utilities, telecommunications services and other inputs
necessary to conduct our business except where a failure to maintain such
supplies or contracts could not reasonably be expected to have a Material
Adverse Effect.
Maintenance of Crude Oil Supply. We will:
. subject to events of force majeure and any other disruptions of
supplies outside our control, maintain supplies of heavy sour crude oil
necessary to conduct our business; and
. during the term of the long term crude oil supply agreement:
. comply in all respects with our obligations under the long term crude
oil supply agreement, the long term crude oil supply agreement
guarantee and the P.M.I. Comercio Internacional consent and
agreement; and
. to the extent required by the long term crude oil supply agreement,
maintain in full force and effect the oil payment guaranty insurance
policy or letters of credit.
Arm's-Length Transactions. We will not enter into any transaction or
agreement with any affiliate unless that transaction or agreement:
. is on terms that at that time are no less favorable to us than those
that could be obtained by us at that time in a comparable arm's length
transaction; and
. has been disclosed to the collateral trustee, the senior lenders and
the oil payment insurers administrative agent.
Year 2000 Compliance. We will ensure that our computer hardware, software,
systems and other operations are year 2000 compliant and will use reasonable
efforts to ensure that the computer hardware, software, systems and operations
of our material suppliers, customers, and others with which it conducts
business to be year 2000 compliant.
Construction and Completion of the Coker Project. We will, among other
things:
. cause the coker project to be constructed in all respects in accordance
with our construction contract with Foster Wheeler USA;
. require Clark Refining & Marketing to cause the property that is to be
leased under the facility and site lease to be upgraded and completed
in all respects, by or before October 2000, subject to extension up to
February 2001 if we satisfy specified conditions; and
. cause the hydrogen supply plant to be constructed in all respects in
accordance with the specifications set forth in the hydrogen supply
agreement by or before December 6, 2000, subject to an extension to
March 2001 if we satisfy specified conditions.
Under specified circumstances, we may be able to change the physical
facilities of our coker project.
Operation of the Project. We will:
. cause the coker project to be constructed, developed, operated,
repaired and maintained in accordance with, among other things,
prudent industry practice, the transaction documents and the major
maintenance plan;
. maintain or caused to be maintained such spare parts and inventory as
are consistent with the transaction documents and prudent industry
practice; and
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. maintain or caused to be maintained at the coker project site a
complete set of plans and specifications for the coker project.
Maintenance of Separate Identity. We will:
. maintain all aspects of our business and operations separate and
apart from the Clark Entities; and
. make all decisions with respect to our business and operations
independently from the Clark Entities.
Environmental Compliance. We will conduct our operations and maintain our
properties and assets in material compliance with all applicable environmental
laws, permits, licenses and other approvals and authorizations.
Project Production. We will:
. enter into arm's-length sales agreements for the sale or disposition
of all our production, including the product purchase agreement, on
terms and conditions consistent with prudent industry practice; and
. in the case of the product purchase agreement and the services and
supply agreement, promptly bill, and cause to be collected from,
Clark Refining & Marketing amounts due and instruct Clark Refining &
Marketing to send all payments directly to the Project Revenue
Account.
Project Documents. We will comply in all respects with, and enforce against
other parties all our rights under, the project documents. We will not agree
to any amendment, waiver, modification, termination or assignment of any of
our rights or obligations under any project document to which we are or become
a party, or provide any consent thereunder, other than in accordance with the
common security agreement.
Maintenance of Separate Identity. We will:
. maintain all aspects of our business and operations separate and
apart from the Clark Entities and hold ourselves out to the public as
an entity independent from the Clark Entities; and
. enter into all business transactions with any Clark Entity on terms
and conditions that at such time are no less favorable to it than
those that could been obtained by us at such time in a comparable
arm's-length transaction.
Except as may be permitted or required by the terms of any financing
document, we will not:
. commingle any of our funds, properties or assets with those of any
Clark Entity;
. guarantee or become obligated for debts of any Clark Entity or hold
out our credit as being available to satisfy any obligations of any
Clark Entity;
. acquire obligations or securities of any Clark Entity;
. pledge our assets for the benefit of, or make any loans or advances
to, any Clark Entity; nor
. incur, create or assume any indebtedness on behalf of, or transfer or
lease our assets or any interest in our assets to, any Clark Entity.
Limitation on Indebtedness. We will not create, incur, assume or suffer to
exist any indebtedness other than Permitted Indebtedness.
Preservation of Security Interests. We will preserve, maintain and perfect
the security interests granted and preserve and protect the collateral. In
addition, we will not, without the consent of Supermajority Secured Parties,
create, assume, incur, permit or suffer to exist any lien upon, or any
security interest in, any of our property, assets or contractual rights,
whether now owned or hereafter acquired, except for Permitted Liens.
Limitation on Investments and Loans. We will not make any investments or
loans or advances to any person, except for Authorized Investments and down
payments or prepayments to suppliers or service providers, other than to any
Clark Entity, and receivables in the ordinary course of business.
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Limitation on Guarantees. We will not assume, guarantee, endorse,
contingently agree to purchase or otherwise become liable upon the obligation
of any other person except:
. by the endorsement of negotiable instruments for deposit or collection or
similar transactions in the ordinary course of business;
. guarantees provided in connection with the granting of performance bonds
to contractors and suppliers and governmental authorities made in the
ordinary course of business; and
. guarantees expressly permitted or required under the financing documents.
Hedging. We will not enter into any swap agreements, option contracts, future
contracts, options on future contracts, spot or forward contracts or other
agreements to purchase or sell or any other hedging arrangements, in each case
in respect of currencies, interest rates, commodities or otherwise other than
Permitted Hedging Instruments.
Use of Proceeds. All proceeds of the initial senior debt, other than the
secured working capital facility, will be used solely to reimburse Clark
Refining & Marketing for operating expenses incurred prior to the closing date
and to pay operating expenses. All proceeds of Additional Senior Debt incurred
to finance or refinance mandatory capital expenditures or discretionary capital
expenditures will be used solely to finance or refinance mandatory capital
expenditures or discretionary capital expenditures, as the case may be. All
proceeds of Replacement Senior Debt will be used to pay or prepay senior debt
or to replace senior debt commitments. Proceeds of the senior debt may be
invested in Authorized Investments prior to being used in accordance with this
covenant.
Independent Consultants. We, on behalf of the secured parties, have appointed
Purvin & Gertz as the initial independent engineer and the initial marketing
consultant and Sedgwick of Tennessee, Inc. as the initial insurance consultant.
Majority Secured Parties, upon 15 days prior written notice to the collateral
trustee and each Applicable Agent, will have the right to remove an independent
consultant if, in the opinion of Majority Secured Parties, that independent
consultant:
. ceases to be a consulting firm of recognized international standing;
. has become an affiliate of us, Sabine River, Neches River, the Clark
Entities, the oil payment insurers, an Applicable Agent or a secured
party;
. has developed a conflict of interest that calls into question such firm's
capacity to exercise independent judgment in the performance of our
duties in connection with the coker project; or
.has failed to charge commercially reasonable compensation for our duties.
If any independent consultant is removed or resigns and thereby ceases to act
as an independent consultant, the bank senior lenders administrative agent will
promptly designate a replacement independent consultant of recognized
international standing.
Subsidiaries. Port Arthur Coker Company will not at any time own any capital
stock or other ownership interest in any person other than Port Arthur Finance.
Neither Port Arthur Coker Company nor Port Arthur Finance will form any new
subsidiary. Port Arthur Coker Company and Port Arthur Finance will at all times
maintain the status of Port Arthur Finance as a wholly owned subsidiary of the
Port Arthur Coker Company.
Credit Rating Agencies. So long as any notes are outstanding, we will take
all actions as may be necessary or appropriate from time to time to cause the
notes to be rated by Moody's and Standard & Poor's. If either Moody's or
Standard & Poor's ceases to be a "nationally recognized statistical rating
organization" registered with the Commission or ceases to be in the business of
rating securities of the type and nature of the notes, we may replace it with
any other nationally recognized statistical rating organization in the business
of rating securities of the type and nature of the notes nominated by us and
approved by Majority Bank Lenders and Majority Bondholders.
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Accounts. We will cause the secured accounts to be established and maintained
at all times in accordance with the common security agreement, will make no
bank accounts other than the secured accounts and the operating account and
will make no transfer, deposit or withdrawal from any secured account, except
in either case as specifically permitted in the common security agreement. Port
Arthur Finance will not establish or maintain any bank account.
Insurance. We will maintain at all times the insurance required to be
maintained in the common security agreement.
ERISA. We will not adopt, sponsor, maintain, administer, contribute to, or
become required to contribute to any employee benefit plan as defined in
Section 3(3) of ERISA.
Further Assurances. We agree to do all things reasonably requested by the
collateral trustee, the bank senior lenders, the oil payment insurers
administrative agent or the indenture trustee to make effective, as soon as
practicable, the transactions contemplated by, and to carry out the purposes
of, the transaction documents.
Oil Payment Guaranty Insurance Policy. We will maintain in place, and make
all payments required to be made in respect of, the oil payment guaranty
insurance policy or letters of credit required under the long term crude oil
supply agreement unless and until the rating of our long-term secured debt
obligations has been at least Baa2 by Moody's and BBB by Standard & Poor's for
at least six consecutive months.
Independent Director. We will give each applicable agent not less than 45
days' prior notice of any appointment of an independent director to its board
of directors in accordance with the Certificate of Incorporation of Port Arthur
Finance and we will not make such appointment if any applicable agent objects
within such 45-day period to such proposed appointment.
Technology. We will take all actions necessary to ensure that we possess, or
have the right to use, all licenses and other rights with respect to technology
prior to Final Completion, and we will maintain in place all licenses and other
rights with respect to technology to the extent necessary for the development,
construction, operation or maintenance of our coker project at any time.
Amounts Received from P.M.I. Comercio Internacional. We will cause any and
all amounts repaid to us by P.M.I. Comercio Internacional, whether as the
result of defenses exercised by us or for any other reason, to the extent such
amounts relate to any shipment of Maya crude oil for which the oil payment
insurers have made payment to P.M.I. Comercio Internacional under the oil
payment guaranty insurance policy, promptly to be paid directly to the oil
payment insurers' administrative agent.
Reports
We are required to deliver the following reports to the collateral trustee,
each credit rating agency and the independent engineer:
. prior to final completion, monthly construction and operating and
progress reports of construction of the coker project and all change
orders requested by Foster Wheeler USA;
. after substantial reliability, monthly operating reports detailing the
status of our operations;
. annual budget and operating plans;
. unaudited quarterly financial statements;
. audited annual financial statements;
. notice of any major maintenance;
. quarterly and annual lists of all permitted hedging instruments; and
. notice of specified extraordinary events.
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Insurance
We are required at all times to keep all project property of an insurable
nature and of a character usually insured, insured with insurers and reinsurers
with a rating by Best's Rating Service no less than A- and a "Financial Size
Category of Class IX" selected by us against such risks, with all risk property
and general liability coverage, including deductibles and exclusions, and in
such form and amounts as are customary for project facilities of similar type
and scale to the heavy oil processing facility, including insurance against
sudden and accidental environmental damage and, prior to substantial
reliability, delay in start-up coverage and, after substantial reliability,
business interruption and contingent business interruption insurance. We are
required, at a minimum and without limiting the generality of the immediately
preceding sentence, to obtain and maintain at least the coverage set forth on
the schedule of required insurance set forth in the common security agreement.
We are required to irrevocably cause:
. with limited exceptions, each of our insurance policies and, to the
extent commercially available, the related reinsurance policies to name
the collateral trustee on behalf of the secured parties and the secured
parties as additional insureds and sole loss payees as their interests
may appear; and
. each of our insurance policies other than third-party liability insurance
and workers' compensation to require all payment of proceeds directly to
the Casualty and Insurance Account or the Catastrophic Casualty Account,
as the case may be.
Events of Default
Each of the following events constitute Events of Default under the common
security agreement:
Payment Default. We default in the payment when due of principal, interest,
premium or other amounts owing in respect of any senior debt or any oil payment
reimbursement obligation, and, in each case, the default remains uncured or
unwaived for more than five business days.
Breach of Representation and Warranty. Any representation or warranty made by
any of us, Sabine River or Neches River proves to have been false or misleading
in any material respect when made.
Breach of Covenant. Any of us, Sabine River or Neches River fails to observe
or perform any obligation to be observed or performed by it under the common
security agreement and such failure continues unwaived or unremedied for 30
days.
Default Under the Financing Documents. An Event of Default has occurred and
is continuing under any financing document.
Default Under or Termination of the Project Documents. Any party to a project
document fails in any material respect to observe or perform any covenant or
other obligation to be observed or performed by it or to pay any amounts owing
by it thereunder and that failure continues uncured, unwaived or unremedied,
. for more than 30 days, in the case of failure under any project document
to which any of our affiliates is a party or in the case of a failure to
pay any amounts owing under the construction contract, the long-term
crude oil supply agreement or the hydrogen supply agreement;
. for more than 60 days, in the case of any other failure under the
construction contract, the long-term crude oil supply agreement or the
hydrogen supply agreement, which grace period will be extended to no more
than 180 days in the aggregate if Port Arthur Coker Company is diligently
pursuing a remedy for such failure, including, without limitation, by
replacing the relevant project document; and
. for more than 30 days, in the case of any other failure under any other
project document.
Insolvency. An insolvency event has occurred with respect to (1) at any time,
any of us, Sabine River or Neches River or (2) prior to substantial
reliability, Blackstone.
Cross-Acceleration. Any indebtedness in an aggregate principal amount in
excess of $5 million of any of us or Sabine River or Neches River has been
declared due and payable or required to be prepaid or redeemed, other than by
regularly scheduled required prepayment or redemption, prior to the stated
maturity
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thereof, or any event or condition has occurred that permits a holder of such
indebtedness to make such a declaration and any applicable grace period in the
financing documents under which such indebtedness was incurred has expired.
Attachment of Collateral. A person other than the collateral trustee, any
Applicable Agents, any of the secured parties or any of their authorized
representatives has attached:
. any secured account or subaccount or funds in any secured account or
subaccount; or
. any portion of our property and assets which property and assets,
individually or in the aggregate, have a book value in excess of $5
million, and such attachment remains unlifted, unstayed or undischarged
for a period of 30 days.
Security Interests Invalid. Any security interests created or purported to be
created by or pursuant to the common security agreement or any security
document are, in the reasonable opinion of counsel to the secured parties, not
valid, perfected, first priority security interests in favor of the collateral
trustee for the benefit of the secured parties to the extent specified in the
legal opinions to be delivered on the closing date.
Unsatisfied Judgments. A final judgment or final judgments in the aggregate
in excess of $5 million with respect to any of us or Sabine River or Neches
River, has been rendered by a court or other competent tribunal against any of
us or Sabine River or Neches River and remains unpaid, unstayed, undischarged,
unbonded or undismissed after the right to appeal has expired.
Unenforceability of Agreements. Any transaction document has been repudiated
or terminated by any party thereto, by operation of law or otherwise, or any
material provision of any transaction document has ceased for any other reason
to be valid, legally binding or enforceable against any party thereto other
than the secured parties if such cessation is not cured within 30 days after
notice to Port Arthur Coker Company.
Abandonment. Abandonment has occurred.
Failure to Achieve Substantial Reliability. We have failed to achieve
substantial reliability by October 2001.
Failure to Achieve Mechanical Completion. We have failed to achieve
mechanical completion by March 2001, or by October 2001 if, commencing in March
2001:
. we continue to pay the senior debt obligations as and when they become
due;
. we accrue monthly all senior debt obligations due and payable on the
immediately succeeding Payment Date and deposit such funds at the end of
each calender month into an escrow account pledged to the collateral
trustee for the benefit of the secured parties;
. we continue to pursue diligently the achievement of mechanical completion
at the earliest practicable date; and
. we have delivered to the collateral trustee a certificate setting forth
in reasonable detail (1) the actions we are taking to achieve mechanical
completion and (2) the proposed timetable for taking such actions, which
certificate will be reviewed and confirmed by the independent engineer.
Clark EPC Contract. The work to be performed by Clark Refining & Marketing in
connection with the refinery upgrade project has not been substantially
completed by October 2000, subject to an extension to February 2001 if the
independent engineer certifies to the collateral trustee that this extension
will not have a material adverse effect on our ability to achieve mechanical
completion by March 2001.
Hydrogen Supply Plant. The hydrogen supply plant has not been completed by
December 2000, or by March 2001 if, commencing in December 2000:
. we continue to pay the senior debt obligations as and when due; and
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. we continue to pursue diligently the achievement of completion of the
hydrogen supply plant by Air Products or by us at the earliest
practicable date.
Failure to Deposit Funds in Accounts. We fail to cause funds to be deposited
into the secured accounts in accordance with the common security agreement and
such failure continues unwaived or unremedied for five business days.
We refer to any event or condition that with the passage of time or the
delivery of notice or both will or could be expected to become an Event of
Default as a "Potential Default."
Remedies
Declaration of Default. A Default will occur:
. upon receipt by the collateral trustee of one or more of:
. a certificate from a senior lender or a senior lender group (or, in
specified circumstances, the oil payment insurers administrative
agent) stating that an Event of Default relating to our payment
obligations has occurred and is continuing and instructing the
collateral trustee to declare a Default; or
. a certificate from Majority Lenders, or, in specified circumstances,
Majority Secured Parties, stating that an Event of Default has
occurred and is continuing and instructing the collateral trustee to
declare a Default; and
. automatically upon an insolvency event.
Remedies. When an Event of Default has occurred with respect to an insolvency
event, all senior debt commitments will automatically terminate and 100% of the
outstanding principal amount of the senior debt, plus any premium, accrued
interest, fees and other amounts due under the bank loan agreements will become
immediately due and payable by us without notice of any kind.
In the case of any other Event of Default:
. the collateral trustee, at the direction of Majority Lenders, or, in
specified circumstances, Majority Secured Parties, will take control
of the secured accounts;
. Majority Lenders, or, in specified circumstances, Majority Secured
Parties, will have the right, at their sole option, to require us to
continue to operate the heavy oil processing facility or to require
us to appoint a manager or operator on terms acceptable to the
Majority Lenders or Majority Secured Parties, as the case may be,
which manager or operator will have the same rights that we had pre-
Default to take all necessary action to operate the heavy oil
processing facility;
. each senior lender group will have the right to apply the relevant
default interest rate provided for in its bank loan agreement or
indenture, as applicable; and
. Majority Lenders, or, in specified circumstances, Majority Secured
Parties, will have the right to instruct the collateral trustee to
take Enforcement Action.
In the case of any Event of Default, Majority Lenders will have the right, at
their sole option, to notify the oil payment insurers administrative agent that
the second payment priority with respect to reimbursement obligations will
terminate, which we refer to as a "Priority Termination Notice." Separately,
either Majority Lenders or the oil payment issuers administrative agent will
notify P.M.I. Comercio Internacional that the coverage provided by the oil
payment guaranty insurance policy will be suspended on the earliest date
permitted under the policy. The second payment priority with respect to
reimbursement obligations will terminate 30 days following the effectiveness of
the suspension under the policy.
Application of Enforcement Proceeds. The collateral trustee will promptly
apply proceeds from the Enforcement Proceeds Account, established by the
collateral trustee upon receipt of a direction of Majority
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Lenders, at the direction of Majority Lenders, or, in specified circumstances,
Majority Secured Parties, in the following order of priority:
. First, to the payment of all fees, indemnities and any other amounts that
we owe to the collateral trustee, the bank senior lenders administrative
agent, the oil payment insurers administrative agent, the indenture
trustee and the depositary bank relating to services rendered in their
capacity as collateral trustee, bank senior lenders administrative agent,
oil payment insurers administrative agent, indenture trustee or
depositary bank, as the case may be;
. Second, to the payment of all fees, costs, expenses, indemnities and any
other amounts that we owe to the secured parties and the whole amount
then outstanding of senior debt obligations or reimbursement obligations
and in case such moneys will not be sufficient to pay in full the whole
amount due and unpaid, then to make equal and ratable payments, without
any preference or priority, as among the secured parties, provided that
any amounts that we owe to the oil payment insurers in respect of
reimbursement obligations relating to shipments of Maya pursuant to the
long term crude oil supply agreement for which title passed to us after
the notice from senior lenders to the oil payment insurers administrative
agent will have priority over any amounts owed to the senior lenders in
respect of senior debt obligations, except to the extent that funds on
deposit in the Debt Service Reserve Account have been applied to pay such
reimbursement obligations; and
. Third, after the payment in full of the senior debt obligations and the
reimbursement obligations, to us or our successors, or in the case of
proceeds from the transfer or disposition of all or part of the interests
in Sabine River or Neches River to the Shareholders or Sabine River, as
the case may be, or as a court of competent jurisdiction may otherwise
direct.
Mandatory Prepayments
Prepayments with Specified Proceeds
Subject to our bank loan agreements, we will apply any of the following
proceeds to the prepayment of senior loans, and, in specified circumstances, to
prepayment of reimbursement obligations, made by the bank senior lenders and
the noteholders:
. any loss proceeds in respect of any catastrophic casualty to project
property, except to the extent that they relate to any shipment of Maya
for which (1) the oil payment insurers have made, or are obligated to
make, payment to P.M.I. Comercio Internacional under the oil payment
guaranty insurance policy or (2) the bank senior lenders have provided
cash advances or letters of credit under the secured working capital
facility, to the extent that such loss proceeds are not applied toward
repairing, replacing or restoring the relevant project property;
. any insurance proceeds in respect of any casualty to project
property, to the extent that those proceeds will not be used to
repair or replace the relevant project property; and
. any late payments, which are not needed to pay interest, buy down
payments or other payments received from Foster Wheeler USA pursuant
to the construction contract to the extent we do not need to direct
these funds to the payment of interest on the senior debt.
Prepayments of Bank Senior Debt
We will make prepayments of the bank senior debt but not the notes, on each
payment date after start-up in an amount equal to 75% of excess cash flow, such
amount to be determined no earlier than on each payment date.
Prepayments of Senior Debt and Oil Payment Insurance Obligations
We will apply the following to the prepayment of senior loans and
reimbursement obligations:
. any loss proceeds in respect of any catastrophic casualty to project
property, except to the extent
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that they relate to any shipment of Maya for which (1) the oil payment
insurers have made, or are obligated to make, payment to P.M.I.
Comercio Internacional under the oil payment guaranty insurance policy
or (2) the bank senior lenders have provided cash advances or letters
of credit under the secured working capital facility, to the extent
that such loss proceeds are not applied toward repairing, replacing or
restoring the relevant project property;
. any delay in start-up, business interruption or contingent business
interruption insurance proceeds that are not transferred to the Project
Revenue Account; and
. upon receipt, any condemnation compensation by governmental authority.
Application of Prepayments
Mandatory prepayments other than those that we make with the 75% of excess
cash flow will be applied equally and ratably between the senior bank loans
and the notes to reduce remaining principal installments equally and ratably
as to each remaining principal installment outstanding.
Mandatory prepayments that we make toward the bank senior debt with the 75%
of excess cash flow will be applied in direct order of maturity until the
principal due on the immediately succeeding Payment Date has been paid in full
and then to reduce the remaining principal installments of senior bank loans
in the inverse order of their maturity.
If any mandatory prepayments required to be made are applied to
reimbursement obligations outstanding at the time of prepayment, the amount or
amounts prepaid will be applied equally and ratably between senior bank loans
and such reimbursement obligations.
Insurance Proceeds
Within 60 days following the occurrence of a catastrophic casualty, we will
deliver to the collateral trustee a plan for the application of these
insurance proceeds and other funds available that are available to us to
restore, repair or replace the project property. If, within 45 days following
the later of the receipt by the collateral trustee of this plan and the
deposit of these proceeds into the Catastrophic Casualty Account, Majority
Lenders, or, in specified circumstances, Majority Secured Parties, notify us
that in their reasonable judgment it is unlikely that, after implementation of
our plan, we would be able to pay the senior debt obligations as and when they
come due or be able to produce product production of substantially the same or
higher quality and quantity as prior to such loss, the casualty insurance
proceeds will remain in the Catastrophic Casualty Account, and we may be
required to apply the proceeds to prepay senior debt and to direct the
collateral trustee to transfer the relevant casualty insurance proceeds from
the Catastrophic Casualty Account to the Mandatory Prepayments Account.
Prepayments arising out of these insurance proceeds will be made within two
business days following such transfer. The senior lenders will have the
option, at our expense, to consult with the independent engineer for purposes
of reviewing any plan for the application of such casualty insurance proceeds
with respect to which Majority Lenders or Majority Secured Parties, as the
case may be, have the right to object.
Promptly upon the receipt of any loss proceeds relating to any shipment of
Maya, we will instruct the collateral trustee to transfer such loss proceeds,
to the extent the oil payment insurers have made, or are obligated to make,
payment to P.M.I. Comercio Internacional under the oil payment guaranty
insurance policy in respect of such shipment, from the Casualty and Insurance
Account or the Catastrophic Casualty Account, as the case may be, to an
account specified for such purpose by the oil payment insurers administrative
agent.
Optional Prepayments
We may make optional prepayments with respect to the senior bank loans and
the notes at any time upon 30 days' prior notice to the collateral trustee and
the Applicable Agent. Any optional prepayment must be accompanied by any
prepayment compensation required under the applicable credit agreements.
Optional
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prepayments will be applied to reduce the remaining principal installments of
senior loans in the order such remaining principal installments become due.
Pro Rata and Non-Pro Rata Payments
Pro Rata Payments
With respect to the senior bank loans and the notes, each payment, optional
prepayment or mandatory prepayment that we will make to a senior lender in
respect of senior debt obligations, other than an optional prepayment or
mandatory prepayment made in accordance with the following paragraph, will be
an equal and ratable payment among the senior bank loans and the notes.
Non-Pro Rata Prepayments
Subject to the terms of the senior loan agreements, we may:
. make an optional prepayment, in whole or in part, of senior loans owed to
senior lenders in one or more senior lender groups without making an
equal and ratable payment to any senior lenders in any other senior
lender group if:
. such payment is made with equity funding;
. such payment is made with the proceeds of Replacement Senior Debt
incurred by us; or
. such payment is made from funds otherwise available for Restricted
Payments;
. make an optional prepayment of senior loans owed to all senior lenders
without making any prepayment to the capital markets senior lenders,
provided that such optional prepayment is a pro rata payment among all
senior lenders, other than the capital markets senior lenders; or
. make a mandatory prepayment in whole or in part of senior debt
obligations owed to any bank senior lender if such mandatory prepayment
is made in accordance with the bank senior loan agreement, or any other
senior lender that is entitled to such mandatory prepayment as
compensation for costs incurred by it in connection with making or
maintaining its senior loans under its senior loan agreement or
indenture, as applicable, in excess of costs incurred generally by the
other senior lenders, or because it has become unlawful for it to honor
its obligation to make or maintain senior loans under its senior loan
agreement or indenture, as applicable, and it has not become unlawful
generally for the other senior lenders to honor their obligations to make
or maintain senior loans to us under their senior loan agreements, in
either case without making an equal and ratable payment to any other
senior lenders, provided that (1) such payment or prepayment is made with
equity funding, (2) such payment or prepayment is made with the proceeds
of Replacement Senior Debt incurred by us or (3) such payment or
prepayment is made from funds otherwise available for Restricted
Payments.
Additional Senior Debt
We may incur, in addition to the initial senior debt, the reimbursement
obligations and any Replacement Senior Debt and without the prior consent of
the senior lenders or the oil payment insurers, Additional Senior Debt secured
by the same common security package, subject to the following conditions:
. if we plan to use the proceeds of the Additional Senior Debt solely to
finance or refinance mandatory capital expenditures, a responsible
officer must certify to the collateral trustee and the independent
engineer that:
. no Event of Default or Potential Default has occurred and is
continuing;
. the amount and scope of such mandatory capital expenditures are
necessary to comply with a change in applicable environmental,
health, safety or other laws or regulations binding on us or are
otherwise necessary to operate the heavy oil processing facility; and
. after giving effect to the incurrence of all Additional Senior Debt,
and based on reasonable assumptions verified by the independent
engineer:
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. the minimum Debt Service Coverage Ratio for each remaining
calendar year through final maturity of the senior debt will be
not less than 1.5:1.0; and
. the average annual Debt Service Coverage Ratio from the date of
incurrence of the Additional Senior Debt through final maturity
of the senior debt will be not less than 2.0:1.0;
. if, at any time after substantial reliability, we plan to use the
proceeds of such Additional Senior Debt solely to finance or refinance
discretionary capital expenditures, a responsible officer must certify to
the collateral trustee and the independent engineer confirms that, among
other things:
. no Event of Default or Potential Default has occurred and is
continuing;
. substantial reliability has occurred;
. after giving effect to the incurrence of all additional senior debt,
and based on reasonable assumptions verified by the independent
engineer:
. the minimum Debt Service Coverage Ratio for each remaining
calendar year through final maturity of the Senior Debt as set
forth in the base case model will be not less than 2.0:1.0; and
. the average annual debt service coverage ratio from the date of
incurrence of such additional senior debt through final maturity
of the senior debt as set forth in the base case model will be
not less than 2.6:1.0; and
. we must obtain a credit rating reaffirmation for the notes by both
Moody's and Standard & Poor's;
. the aggregate principal amount of all such Additional Senior Debt for
discretionary capital expenditures does not exceed $20 million if any
bank senior debt remains outstanding, or $50 million if no bank
senior debt remains outstanding;
. that Additional Senior Debt ranks in right of payment, upon
liquidation and in all other respects on an equal and ratable basis
with all other senior debt without preference among senior debt
obligations by reason of date of incurrence or otherwise and has none
of the preferences with respect to reimbursement obligations; and
. the lender of the Additional Senior Debt has executed and delivered
to the collateral trustee an agreement, which includes a copy of the
proposed senior loan agreement relating to the Additional Senior
Debt, setting out that it agrees:
. to become a party to the common security agreement and the
transfer restrictions agreement described under "Description of
Our Principal Financing Documents--Transfer Restrictions
Agreement" below;
. to be bound as a senior lender by all the terms and conditions of
the common security agreement and the transfer restrictions
agreement; and
. to perform all the obligations of a senior lender under the
common security agreement and the transfer restrictions
agreement.
Any incurrence of Additional Senior Debt other than in accordance with the
above terms will require the prior consent of Requisite Lenders.
Replacement Senior Debt
We may incur Replacement Senior Debt, secured by the same common security
package and entitled to the benefits of the common security agreement and the
security documents, to replace the initial senior debt, without the consent of
the senior lenders or the oil payment insurers for the purpose of paying or
prepaying all or any part of the initial senior debt or replacing all or part
of the unutilized or canceled part of the related outstanding senior debt
commitments, subject to the specified conditions including the following:
. the aggregate principal amount of such Replacement Senior Debt
does not exceed the sum of
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the amount of senior debt obligations being paid or prepaid and
the unutilized or canceled part of the senior debt commitments
being replaced;
. the Replacement Senior Debt has a Weighted Average Life no
shorter, and a final maturity date no earlier, than that of the
Senior Debt being replaced;
. the projected average debt service coverage ratio through January
15, 2009, calculated on a pro forma basis reflecting the
incurrence of the Replacement Senior Debt but not modifying any
of the other assumptions made in the base case model described in
Annex B to this prospectus is not less than 2.2:1.0; and
. we have obtained a reaffirmation of the then current credit
rating of notes by both Moody's and Standard & Poor's, provided
that no reaffirmation will be required if the Replacement Senior
Debt is Bank Senior Debt and bears interest at a rate, or, in the
case of a floating rate facility, a margin, that is equal to or
lower than that on the Bank Senior Debt being replaced and no
changes other than the interest rate or margin, as applicable, or
administrative, procedural, mechanical or other de minimis
changes are made.
Any incurrence of Replacement Senior Debt other than in accordance with these
conditions will require the prior consent of Requisite Lenders.
Replacement for Oil Payment Guaranty Insurance Policy
We may enter into one or more letters of credit or similar instruments
satisfying the requirements of the long term crude oil supply agreement to
replace the oil payment insurance guaranty policy in its entirety, but not in
part, without the consent of the senior lenders or the oil payment insurers,
provided that the conditions specified in the common security agreement are
satisfied.
Guarantee
Each of Port Arthur Coker Company, Sabine River and Neches River have
unconditionally and fully guaranteed jointly and severally, all obligations of
Port Arthur Finance under the common security agreement and the other financing
documents.
Governing Law
The common security agreement is governed by the laws of the State of New
York.
Secured Construction and Term Loan Agreement
We, the bank senior lenders and the bank lenders administrative agent entered
into a loan agreement, dated as of August 19, 1999, that provides for our
borrowing from the bank senior lenders $325 million to finance the
construction, development and operation of our coker project. The secured
construction and term loan facility is split into a Tranche A of $225 million
with a term of 7.5 years and a Tranche B of $100 million with a term of 8
years. Under specified circumstances, the aggregate amount of the construction
and term loan facility may be reallocated between the tranches with our
consent, which may not be unreasonably withheld. In November 1999, the bank
senior lenders requested that we reallocate $5 million from Tranche A to
Tranche B. Tranche A loans will be amortized over time. As required under the
secured construction and term loan agreement, we drewdown the entire amount of
the Tranche B loans in October 1999. Other than the $500,000 semiannual
principal payments discussed below, all principal amount of the Tranche B loans
will be due and payable on maturity. Drawdowns of the construction and term
loans must be accompanied by equal and ratable contributions of equity or
deeply subordinated debt from Blackstone and Occidental. We will make interest
and principal payments on the Tranche A loans semiannually on each January 15
and July 15, commencing on
January 15, 2000 in the case of interest and on January 15, 2002 in the case of
principal. With respect to the Tranche B loans, we will make interest payments
quarterly on each January 15, April 15, July 15 and October 15, commencing on
January 15, 2000, and we will make principal payments in the amount of $500,000
semiannually on each January 15 and July 15, commencing on January 15, 2002,
with the remaining principal being repaid in full on the maturity date.
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Senior debt obligations under the construction and term loan agreement rank
equally and ratably in right of payment and liquidation with each other and
with all other senior debt obligations. Senior debt obligations under the
construction and term loan agreement in general also rank equally and ratably
in right of liquidation with our reimbursement obligations relating to the oil
payment guaranty insurance policy described under "Description of Our Principal
Financing Documents--Guaranty Insurance Policy and Reimbursement Agreement"
below, but will generally rank junior in right of payment to those
reimbursement obligations.
Secured Working Capital Facility
Under a secured working capital facility, the bank senior lenders will
provide us up to $35 million of working capital in the form of cash advances or
letters of credit. In February 2000, our working capital facility was reduced
from $75 million to $35 million. The $40 million reduction, a portion of which
had been outstanding in the form of a letter of credit to P.M.I. Comercio
Internacional to secure against a default by us under our long term oil supply
agreement, was replaced by an insurance policy under which an affiliate of
American International Group agreed to insure P.M.I. Comercio Internacional
against our default under the long term oil supply agreement up to a maximum
liability of $40 million. This affiliate of American International Group is
treated as a bank senior lender under the common security agreement. The $35
million available under the secured working capital facility may be used to
meet cash needs of our coker project. Drawdowns under the secured working
capital facility, other than letters of credit provided in connection with the
long term crude oil supply agreement, will rank equally and ratably in right of
payment and liquidation with all other senior debt obligations. The letters of
credit provided in connection with the long term crude oil supply agreement
will rank equally and ratably, in all respects, with our reimbursement
obligations relating to the oil payment guaranty insurance policy.
Oil Payment Guaranty Insurance Policy and Reimbursement Agreement
Winterthur issued an oil payment guaranty insurance policy for the benefit of
P.M.I. Comercio Internacional in order to guarantee our payment obligations to
P.M.I. Comercio Internacional under the long
term crude oil supply agreement for shipments of Maya. We will pay the premiums
and any interest with respect to any amounts drawn under the oil payment
guaranty insurance policy to Winterthur. Winterthur will reinsure a portion of
its exposure under the oil payment guaranty insurance policy with a syndicate
of reinsurers.
Maximum Amount. For the period from and including the coverage start date to
and including the date on which we give the full coverage start notice to the
oil payment insurers, the maximum coverage amount is $15 million, and after
that period, the maximum coverage amount is $150 million. In each case, the
coverage available to us is the maximum amount less any outstanding
reimbursement obligations that we owe to the oil payment insurers.
Coverage Period. The coverage must start no later than March 1, 2001, subject
to extension up to October 1, 2001, provided that Majority Secured Parties may
vote to extend the outside start date up to March 1, 2002. Coverage under the
oil payment guaranty insurance policy will terminate upon the earlier of (1)
10.5 years after the closing date and (2) the date on which all senior debt
obligations have been repaid in full.
Premiums. The annual premium was paid in advance on August 19, 1999, and will
be payable annually in advance on each anniversary of such date.
Security. Under the reimbursement agreement, payments by the oil payment
insurers to P.M.I. Comercio Internacional on our behalf give rise to
reimbursement obligations in favor of the oil payment insurers that we must
repay. The oil payment insurers will be a party to, and get the benefit of, the
common security agreement, the intercreditor agreement and the transfer
restrictions agreement. In particular, the oil payment insurers share on an
equal and ratable basis in the first priority security interest in all
collateral granted to all secured parties under the common security agreement,
but have the possibility for priority access as described under "--Payment and
Liquidation Priorities" below.
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Payment and Liquidation Priorities. For purposes of the cash waterfall in the
common security agreement, reimbursement obligations will at all times rank
below our operating expenses but above senior debt obligations. However, if
senior lenders, following the occurrence of an Event of Default, notify the oil
payment insurers administrative agent that the oil payment insurers priority
position will terminate, any reimbursement obligations that remain unpaid after
30 days following the effectiveness of that notice will be treated like senior
debt obligations in the cash waterfall. Immediately prior to the expiration of
that 30-day period, the collateral trustee will be instructed to apply any
amounts that are then on deposit in the Project Revenue Account, less any
amount earmarked to pay outstanding invoices for oil payments or other project
expenses in the ordinary course of business, to repay any outstanding
reimbursement obligations.
For purposes of liquidation rights, oil payment insurers administrative
agents generally rank equally and ratably with all other senior debt. If,
however, an Event of Default occurs under the common security agreement, but
senior lenders do not notify the oil payment insurers administrative agent that
the oil payment insurers' priority position will terminate, then the oil
payment insurers have the right to request the senior lenders to permit
satisfaction in full of all reimbursement obligations then outstanding. If and
to the extent that outstanding reimbursement obligations are not satisfied
within the 30 calendar days immediately following notice from us to the
collateral trustee and the administrative agents of the relevant default, then
any and all reimbursement obligations arising in respect of shipments of Maya
originating after the notice from us will have priority in right of
liquidation, in addition to the payment priority described above, over all
other senior debt.
Voting Rights. Upon the expiration of the 30-day period referred to above,
the oil payment insurers will become vested with all voting rights of senior
debt holders, to the extent of reimbursement obligations then outstanding. At
all other times, the oil payment insurers will have voting rights, based upon
the maximum amount, only under specified circumstances.
Suspension Events. Upon the occurrence of any of the following events and
following five days notice to P.M.I. Comercio Internacional, the oil payment
insurers may in their sole discretion suspend the coverage provided with
respect to any shipments of Maya thereafter, provided that shipments for which
title has already passed to us will continue to be covered by the oil payment
guaranty insurance policy:
. if (1) the premium for the oil payment guaranty insurance policy is not
paid in full when due, (2) such default is not cured within 10 business
days immediately following the due date and (3) P.M.I. Comercio
Internacional has been notified, then the oil payment guaranty insurance
policy coverage may be suspended for the relevant year until the premium
is paid in full; and
. if (1) senior lenders have notified the oil payment insurers
administrative agent that the oil payment insurers' priority position
will terminate, then the coverage will be suspended for the duration of
the relevant default.
Termination Events. Upon the occurrence of any of the following events and
following five days notice thereof to P.M.I. Comercio Internacional, Winterthur
may in its sole discretion terminate, or, at its election, suspend, the
coverage provided with respect to any shipments of Maya thereafter, provided
that shipments for which title has already passed to us will continue to be
covered by the oil payment guaranty insurance policy:
. an Event of Default under the common security agreement caused by a
payment default or termination of principal project documents has
occurred and continued for at least six months;
. an insolvency event has occurred with respect to (1) at any time, any of
us, Sabine River or Neches River or (2) prior to substantial reliability,
Blackstone;
. abandonment has occurred;
. senior lenders are taking Enforcement Action under the common security
agreement in respect of any other Event of Default;
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. the coverage provided by the oil payment guaranty insurance policy has
been suspended for at least 30 consecutive days, or, if applicable, 30
consecutive days following the expiration of any cure period; or
. we have failed to give Winterthur a notice to start coverage under the
oil payment guaranty insurance policy by the dates set forth in "--
Coverage Period" above.
If Winterthur gives notice of suspension or termination of the oil payment
guaranty insurance policy to P.M.I. Comercio Internacional more than five days
but less than eight days prior to the scheduled loading of one of our Maya
shipments, P.M.I. Comercio Internacional's claim under the oil payment guaranty
insurance policy may include the liquidated damages payable with respect to
late cancellations of scheduled shipments under the long term crude oil supply
agreement in an amount equal to 15% of the price of the cancelled shipment.
We, the oil payment insurers and the oil payment insurers administrative
agent entered into a reimbursement agreement dated as of August 19, 1999.
Pursuant to the reimbursement agreement, payments made by the oil payment
insurers in respect of a claim by P.M.I. Comercio Internacional under the oil
payment guaranty insurance policy will result in our corresponding, immediately
payable reimbursement obligations that are due no later than six months
following the date of their incurrence. In addition, to the extent the oil
payment insurers have made payments with respect to particular shipments of
Maya, it will be subrogated to any and all rights we may have (1) against any
other insurer with respect to such shipments, for example, based upon marine or
casualty insurance, or (2) against the beneficiary for any payments to be
returned.
Oil payment insurance reimbursement obligations will accrue interest on a
daily basis at a rate per annum of 7-day LIBOR plus the applicable margin plus
2%.
Any failure by us to pay in full any oil payment insurers administrative
agent within the six months following the incurrence of such oil payment
insurers administrative agent will constitute an Event of Default under the
common security agreement.
Debt Service Reserve Insurance Guarantee
Winterthur issued a debt service reserve insurance guarantee on August 19,
1999, for the benefit of the secured parties in order to guarantee up to $60
million to the credit of the Debt Service Reserve Account. However, we and the
collateral trustee may mutually agree to reduce this amount permanently.
Winterthur will reissue a portion of its exposure under the debt service
reserve insurance guarantee with the same syndicate of reinsurers that will
reinsure the guaranty insurance policy.
The debt service reserve insurance guarantee is available if, and only to the
extent that, the funds then on deposit in the Principal & Interest Accrual
Account and the Debt Service Reserve Account are insufficient to make scheduled
payments on the senior debt on a payment date. The amount that may be drawn on
any Payment Date is equal to the aggregate amount of senior debt obligations
then due less (1) the balance in the Principal & Interest Accrual Account and
(2) the balance in the Debt Service Reserve Account, including, in each of
cases (1) and (2), cash and any Authorized Investments. We may not draw down
solely for the purpose of covering any shortfall in the Debt Service Reserve
Account at any time if no senior debt obligations are then due.
Coverage Period. Drawings will be permitted during the period commencing on
the date substantial reliability is achieved and ending on the tenth Payment
Date after that date, provided that the coverage will automatically terminate
early if and when the debt service reserve insurance guarantee is replaced.
Premium and Interest. We paid the annual premium for the coverage provided by
the agreement in advance on August 19, 1999, and must pay the premium annually
in advance on each anniversary such date.
Any amounts that we draw down under this arrangement will accrue interest on
a daily basis at a rate of 500 bps above 7-day LIBOR.
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Subordination. Payments of interest on drawdowns under this arrangement will
be subordinated in right of payment to (1) the prior payment in full of all
senior debt obligations and all oil payment insurance obligations related to
the guaranty insurance policy then due and (2) any deposits then required to be
made into the Principal and Interest Accrual Account, Tax Reserve Account,
Major Maintenance Account, Debt Service Reserve Account and P.M.I. Surplus
Reserve Account, but excluding any Restricted Payments. Payments of principal
in respect of drawdowns will be further subordinated. We may only make
repayments of principal in respect of drawdowns under the agreement on a
Payment Date, after applying the 75% of the cash flow available at priority
position tenth under "--Common Security Agreement--Accounts Structure--
Withdrawal from Accounts Pre-Default" to the prepayment of bank senior debt
obligations as set forth in the common security agreement. Once the bank senior
debt is repaid, we may repay principal in respect of drawdowns using 100% of
such cash flow, as set forth in the common security agreement.
Pledge. Winterthur is required to pledge any amounts extended under the debt
service reserve insurance guarantee to the secured parties.
Subordinated Lien on Collateral. Winterthur has a subordinated lien on all
collateral that we have pledged to the senior lenders. This subordinated lien
secures our obligation to reimburse Winterthur for payments made by it under
the debt service reserve insurance guaranty.
Scheduled Contributions to Debt Service Reserve Account. Pursuant to the
common security agreement, on the sixth Payment Date and each of the four
immediately succeeding Payment Dates, we must deposit at least $12 million into
the Debt Service Reserve Account, but no deposits will be required to the
extent the minimum balance of the Debt Service Reserve Account required at any
time has already been reached through payments out of excess cash flow as
described below. Upon each deposit, the guarantee amount available under this
arrangement will be automatically and permanently reduced by a corresponding
amount. These scheduled contributions to the Debt Service Reserve Account will
be subordinated in right of payment to payments of interest on drawdowns under
the arrangement.
Replacement of Debt Service Reserve Insurance Guarantee. On each Payment Date
after substantial reliability during the coverage period, so long as no
principal amount drawn under the agreement remains outstanding, we will be
required to transfer additional funds to the Debt Service Reserve Account in an
amount equal to 25% of the cash flow available at priority position tenth under
"--Common Security Agreement--Accounts--Withdrawal from Accounts Pre-Default"
after applying 75% of such cash flow to the prepayment of bank senior debt. At
any time when the construction and term loans are repaid and all commitments to
lend under those loans have been terminated, we will be required to transfer
funds in an amount equal to 100% of such cash flow to the Debt Service Reserve
Account. Upon each such transfer, the guarantee amount available under this
arrangement will be automatically and permanently reduced by a corresponding
amount. If and when the Debt Service Reserve Account has been fully funded up
to the amount of senior debt obligations due within the succeeding six-month
period, this arrangement will automatically terminate and thereafter the
obligation to fund the Debt Service Reserve Account will rest solely with us.
Acceleration. Our obligations under this arrangement cannot be accelerated
and no Event of Default can be declared by Winterthur unless and until (1) the
secured parties have done so pursuant to the common security agreement or (2)
all outstanding senior debt obligations have been repaid in full, whichever
occurs first.
Transfer Restrictions Agreement
We, Clark Refining Holdings, Sabine River, Neches River, Blackstone, the
collateral trustee, the bank lenders administrative agent, the oil payment
insurers administrative agent and the indenture trustee entered into a transfer
restrictions agreement, dated as of August 19, 1999, that generally provides
that none of us, Clark Refining Holdings, Sabine River, Neches River nor
Blackstone will effect, or permit any Affiliate to
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effect, any transfer of such party's direct or indirect interest, if any, in
us, Clark Refining & Marketing or the Port Arthur refinery. Transfers will be
permitted in limited situations, including those set forth below.
Transfers by Blackstone. Blackstone has the right to dispose of its equity
interest in Clark Refining Holdings:
. prior to final completion of our coker project:
. to a transferee that is rated investment grade by both Standard &
Poor's and Moody's after giving effect to the transfer; or
. any other transferee with (1) the affirmative vote of 51% of bank
lenders and (2) the affirmative vote of 51% of the noteholders or the
reaffirmation by both Standard & Poor's and Moody's of the then-
current credit rating applicable to the notes, provided that either
Blackstone retains its equity funding commitment obligation or the
transferee assumes such obligations; or
. in part but not in whole by means of a primary or secondary public or
Rule 144A offering or private sale, so long as Blackstone (1) retains
not less than 40% of the total capital stock outstanding of Clark
Refining Holdings or (2) remains the largest single direct or
indirect shareholder of Clark Refining Holdings and maintains the
direct or indirect right to appoint no fewer than one-third of the
members of the board of directors of Clark Refining Holdings provided
in each case that Blackstone retains its obligations to fund any
unfunded equity commitment; and
. following final completion of our coker project, in any manner.
Transfers by Clark Refining Holdings. Following final completion, Clark
Refining Holdings may dispose of its indirect interest in the Port Arthur
refinery, Clark Refining & Marketing and Port Arthur Coker Company, in whole
but not in part, to a transferee that is engaged in petroleum refinery
operations or continuous chemical processes, provided that if the transferee is
not rated investment grade by both Standard & Poor's and Moody's after the
transfer, (1) Clark Refining Holdings has obtained the consent of Majority
Lenders and (2) Standard & Poor's and Moody's have reaffirmed the rating on the
Senior Debt at or above the then-current rating, provided further that, in any
case, if the transfer is by means other than a transfer of all the shares of
Clark Refining & Marketing or Clark USA, the transferee assumes all obligations
of Clark Refining & Marketing with respect to the coker project.
Other Transfers. Any other transfer will require the consent of requisite
lenders.
Intercreditor Agreement
The intercreditor agreement governs the rights and obligations, including
sharing of information, notice of non-pro rata payments, general consultation,
voting restrictions and termination of commitments, among the collateral
trustee, acting on behalf of the secured parties, the bank lenders
administrative agent, acting on behalf of the bank senior lenders, the oil
payment insurers administrative agent, acting on behalf of the oil payment
insurers, and the indenture trustee, acting on behalf of the noteholders.
Registration Rights Agreement
Pursuant to the registration rights agreement, we have agreed with the
initial purchasers, for the benefit of the holders of the notes, that we will
file and use our reasonable best efforts to cause to become effective, at our
cost, either a registration statement with respect to a registered offer to
exchange the notes for a series of debt securities which are in all material
respects substantially identical to the notes or a shelf registration covering
resales of the notes. Upon a registration statement with respect to the
exchange offer being declared effective, we will offer the exchange notes in
return for surrender of the notes. The offer will remain open for no less than
20 business days after the date notice of the exchange offer is mailed to you.
For each outstanding
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note surrendered to us under the exchange offer, you will receive exchange
notes in an equal principal amount. Interest on each exchange note will accrue
from the last date on which interest was paid on the outstanding note so
surrendered or, if no interest has been paid, since August 19, 1999.
In the event that we determine in good faith that applicable interpretations
of the staff of the Securities and Exchange Commission or other circumstances
specified in the registration rights agreement do not permit us to effect such
an exchange offer, or we so elect, we will, at our cost, use reasonable best
efforts, subject to customary representations and agreements of the noteholders
to have a shelf registration statement covering resale of the notes declared
effective and kept effective for up to two years after the closing date,
subject to specified exceptions in the registration rights agreement. We will,
in the event of such a shelf registration, provide to each noteholder copies of
the prospectus, notify noteholders when a registration statement for the notes
has become effective and take other actions as are appropriate to permit resale
of the notes.
In the event that such exchange offer is not consummated or such registration
statement is not declared effective within 270 days following the closing date,
the annual interest rates on the notes will increase by one half of one
percent, 50 basis points, effective on the 271st day following the closing
date, which increase will remain in effect until the date on which such
exchange offer is consummated or such registration statement will have become
effective.
Each noteholder who wishes to exchange its outstanding notes for exchange
notes in the exchange offer will be required to represent, among other things,
that any exchange notes to be received by it will be acquired in the ordinary
course of business and that at the time of the commencement of the exchange
offer it will have no arrangement with any person to participate in the
distribution of the exchange notes within the meaning of the Securities Act.
A noteholder that sells its notes pursuant to a shelf registration generally
will be required to be named as a selling holder in the related prospectus and
to deliver a prospectus to purchasers, will be subject to applicable civil
liability provisions under the Securities Act in connection with such sale and
will be required to agree in writing to be bound by the provisions of the
registration rights agreement which are applicable to such noteholder,
including indemnification obligations.
Definitions for Our Financing Documents
"Applicable Agent" means, (1) in the case of the noteholders, the indenture
trustee, (2) in the case of the initial bank lender group, the bank lenders
administrative agent, (3) in the case of any other senior lender group, the
person notified to the collateral trustee as the Applicable Agent for such
senior lender group, and (4) in the case of the oil payment insurers, the oil
payment insurers administrative agent.
"Authorized Investments" means (1) investments maturing within one year after
the acquisition thereof in (a) United States government securities, (b)
deposits with banks or trust companies with a rating of at least A-1 from
Moody's and A from Standard & Poor's and at least $500 million of shareholders'
equity or (c) commercial paper by an issuer rated at least P-1 from Moody's and
A-1 from Standard & Poor's and which has at least $500 million of shareholders'
equity or (2) investments in any money market fund having a rating in the
highest investment category granted by Moody's or Standard & Poor's, including
any such fund for which the depositary bank or any affiliate thereof serves as
investment manager, administrator or custodian.
"Clark Entities" means Clark Refining Holdings, Clark USA and Clark Refining
& Marketing.
"Debt Service Coverage Ratio" means for any period, the ratio of (1) the
aggregate of cash proceeds minus project expenses for such period to (2) senior
debt obligations, other than pursuant to optional prepayments or mandatory
prepayments, paid or expected to be paid during such period, as the case may
be.
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"Enforcement Action" means, any or all of the following: (1) the application
charge or set-off of funds in the secured accounts to the payment of senior
debt obligations and the oil payment insurers administrative agents, (2) the
declaration of the principal of the senior debt immediately due and payable,
(3) the exercising of any power of sale or other rights granted by any
financing document, and (4) the taking of any other legal, equitable or other
remedy or action.
"Majority Bank Lenders" means holders of more than 50% of the aggregate
outstanding principal amount of bank senior debt, including, without limitation
any insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, and bank senior debt commitments.
"Majority Bondholders" means holders of more than 50% of the aggregate
outstanding principal amount of the notes.
"Majority Lenders" means, (1) at any time when the aggregate outstanding
principal amount of bank senior debt, including, without limitation, any
insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, and bank senior debt commitments is equal to
or exceeds 15% of the aggregate outstanding principal amount of senior debt and
senior debt commitments, either (a) Majority Bank Lenders or (b) holders of
more than 25% of the aggregate outstanding principal amount of the notes, and
(2) at any time when the aggregate outstanding principal amount of bank senior
debt, including, without limitation, any insurance product replacing the
"Compensating Letter of Credit" under the secured working capital facility and
bank senior debt commitments is less than 15% of the aggregate outstanding
principal amount of senior debt and senior debt commitments, the holders of
more than 25% of the aggregate outstanding principal amount of senior debt and
senior debt commitments.
"Majority Secured Parties" means either (1) holders of more than 50% of the
aggregate principal amount of bank senior debt, including, without limitation,
any insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, bank senior debt commitments and the oil
payment commitment, or, under specified circumstances, the aggregate principal
amount of oil payment reimbursement obligations then outstanding, taken
together, or (2) holders of more than 25% of the aggregate outstanding
principal amount of the notes.
"Material Adverse Effect" means a material adverse effect on (1) the
business, assets, operations, properties, financial condition or prospects of
any of us or Sabine River or Neches River, (2) our ability to construct the
coker project and operate the heavy oil processing facility in accordance with
the transaction documents, (3) the rights and remedies of any secured party,
(4) our ability to pay any senior debt obligations when due or (5) the ability
of any of us or Sabine River or Neches River, our affiliate or any other party
to perform its material obligations under any transaction document.
"Permitted Indebtedness" means (1) indebtedness in respect of our obligations
under the financing documents, (2) permitted hedging instruments, (3) trade
accounts payable in the ordinary course of business and (4) subordinated debt.
"Permitted Liens" means (1) liens to secure senior debt obligations, (2)
judgment liens that are not currently dischargeable or that have been
discharged or stayed or appealed within 30 days after the date of such
judgment, (3) subordinated liens securing our reimbursement obligations under
the debt service reserve insurance guarantee or our obligations under the long
term crude oil supply agreement, (4) liens on cash eligible for restricted
payments under the common security agreement and (5) some other customary
permitted liens.
"Projected Tax Reserve Amount" means the total of (1) the amount of taxes
other than income or franchise taxes or operational taxes that are considered
Project Expenses projected to become due and payable on or before the next two
succeeding Payment Dates and (2) the amount of income or franchise taxes that
are
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projected to be incurred or that will become due and payable on or before the
next two Payment Dates by Sabine River and/or Neches River either directly to a
taxing authority or pursuant to the Tax Sharing Agreement in respect of their
allocable share of the taxable income of Port Arthur Coker Company.
"Requisite Bank Lenders" means holders of more than 66 2/3% of the aggregate
principal amount of bank senior debt, including without limitation any
insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, and bank senior debt commitments.
"Requisite Lenders" means (1) at any time when the aggregate outstanding
principal amount of bank senior debt, including without limitation any
insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, and bank senior debt commitments is equal to
or exceeds 15% of the aggregate outstanding principal amount of senior debt and
senior debt commitments, (a) Requisite Bank Lenders and (b) either Majority
Bondholders, or, under specified circumstances, Requisite Bondholders, or a
ratings reaffirmation of the notes by both Moody's and Standard & Poor's, and
(2) when the aggregate outstanding principal amount of bank senior debt,
including without limitation any insurance product replacing the "Compensating
Letter of Credit" under the secured working capital facility, and bank senior
debt commitments is less than 15% of the aggregate outstanding principal amount
of senior debt and senior debt commitments, either (a) the holders of more than
50% of the aggregate outstanding principal amount of senior debt and senior
debt commitments or (b) a ratings reaffirmation of the notes by both Moody's
and Standard and Poor's.
"Requisite Secured Parties" means (1) holders of more than 66 2/3% of the
aggregate principal amount of bank senior debt, including without limitation
any insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, bank senior debt commitments and the oil
payment commitment, or, under specified circumstances, the aggregate principal
amount of oil payment reimbursement obligations then outstanding, taken
together, and (2) either (a) Majority Bondholders, or, in specified
circumstances, Requisite Bondholders, or (b) a credit rating reaffirmation or
the notes by both Moody's and Standard & Poor's.
"Shareholder" means each of Blackstone, Occidental and Clark Refining Holding
and each other shareholder, directly or indirectly, holding the outstanding
capital stock of Sabine River.
"Supermajority Bank Lenders" means holders of more than 75% of the aggregate
outstanding principal amount of bank senior debt and bank senior debt
commitments.
"Supermajority Lenders" means (1) at any time when the aggregate outstanding
principal amount of bank senior debt, including without limitation any
insurance product replacing the "Compensating Letter of Credit" under the
secured working capital facility, and bank senior debt commitments is equal to
or exceeds 15% of the aggregate outstanding principal amount of senior debt and
senior debt commitments, Supermajority Bank Lenders and either Supermajority
Bondholders or a ratings reaffirmation of the notes by both Moody's and
Standard & Poor's, and (2) at any time when the aggregate outstanding principal
amount of bank senior debt, including without limitation any insurance product
replacing the "Compensating Letter of Credit" under the secured working capital
facility, and bank senior debt commitments is less than 15% of the aggregate
outstanding principal amount of senior debt and senior debt commitments, (a)
holders of more than 75% of the aggregate outstanding principal amount of
senior debt and senior debt commitments or (b) a credit ratings reaffirmation
of the notes by both Moody's and Standard & Poor's.
"Supermajority Secured Parties" means (1) holders of more than 75% of the
aggregate outstanding principal amount of bank senior debt, including without
limitation any insurance product replacing the "Compensating Letter of Credit"
under the secured working capital facility, bank senior debt commitments and
the oil payment commitment, or, under specified circumstances, the aggregate
principal amount of oil payment reimbursement obligations then outstanding,
taken together, and (2) either (a) Supermajority Bondholders or (b) a credit
ratings reaffirmation of the notes by both Moody's and Standard & Poor's.
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"Weighted Average Life" means, when applied to any Indebtedness at any date,
the number of years obtained by dividing (1) the total of the products obtained
by multiplying (a) the amount of each then remaining installment, sinking fund,
serial maturity or other required payments of principal, including payment at
final maturity, in respect thereof, by (b) the numbers of years calculated to
the nearest one-twelfth that will elapse between such date and the making of
such payment, by (2) the then outstanding principal amount of such
Indebtedness.
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BOOK-ENTRY; DELIVERY AND FORM
The exchange notes will initially be represented by one or more permanent
global notes in definitive, fully registered book-entry form, without interest
coupons that will be deposited with, or on behalf of, DTC and registered in the
name of DTC or its nominee, on behalf of the acquirors of exchange notes
represented thereby for credit to the respective accounts of the acquirors, or
to such other accountants as they may direct, at DTC, or Morgan Guaranty Trust
Company of New York, Brussels office, as operator of the Euroclear System, or
Cedel Bank, societe anonyme. Procedures for tendering outstanding notes in the
exchange offer through the DTC book-entry system are described under "The
Exchange Offer--Book Entry Transfer."
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SPECIAL LEGAL ASPECTS
We have taken steps in structuring the transactions contemplated hereby that
are intended to ensure that the voluntary or involuntary application for relief
under the United States Bankruptcy Code or similar state laws by Clark Refining
& Marketing, Clark Refining Holdings or Clark USA will not result in the
consolidation of our assets and liabilities with those of such entities or any
of their affiliates, other than Blackstone, Occidental, Sabine River or Neches
River. These steps include:
. the appointment of an independent director to the board of directors of
each of the two corporate partners of Port Arthur Coker Company and to
Port Arthur Finance;
. our creation, and the creation of Sabine River and Neches River, pursuant
to organizational documents containing limitations, including
restrictions on the nature of our and their, business and restrictions on
our, and their, ability to commence a voluntary case or proceeding under
bankruptcy law with respect to ourselves without the prior unanimous
affirmative vote of all of our, or their, directors;
. the on-going maintenance of Occidental's 10% common equity ownership in
Sabine River separate and independent from the ownership interest of
Clark Refining Holdings;
. the operation of our new processing units by our own employees and our
employment of an individual responsible for our accounting and
. our agreement to covenants intended to ensure the maintenance of our
separate existence, including, among other covenants, to maintain
separate books and records, to conduct our business in our own name.
However, notwithstanding the foregoing, we cannot assure you that our
activities would not result in a court concluding that our assets and
liabilities should be consolidated with those of Clark Refining &
Marketing, Clark Refining Holdings or Clark USA in a proceeding under any
bankruptcy law. If a court were to reach such a conclusion, then delays
in distributions on the notes could occur or reductions in the amounts of
such distributions could result.
We have received an opinion of our counsel to the effect that, subject to
specified facts, assumptions and qualifications, it would not be a proper
exercise by a court of its equitable discretion to disregard separate existence
and to require the consolidation of our assets and liabilities with the assets
and liabilities of Clark Refining & Marketing, Clark Refining Holdings or Clark
USA in the event of the application of any bankruptcy law to any of these
entities. Such opinion, however, points out that the risk of substantive
consolidation may be higher in a situation in which unique assets critical to
the business operations and successful reorganization of the bankrupt--so
called "core assets"--are held by a related entity and there is relatively
little judicial experience with respect to assets that may be considered "core
assets" of a debtor.
In addition, among other things, this opinion of counsel assumes, for
purposes of such opinion, that we will follow procedures in the conduct of our
affairs, including maintaining separate records, books of account and bank
accounts, maintaining adequate capital, refraining from commingling our assets
and refraining from holding ourselves out as having agreed to pay, or being
liable for, each other's debts and that the 10% equity interest of Occidental
in our general partner will be maintained and no portion of such interest will
be transferred, directly or indirectly to Clark Refining & Marketing, Clark
Refining Holdings or Clark USA. We and Clark Refining & Marketing will
represent to such counsel that we and Clark Refining & Marketing will follow
these and other procedures related to maintaining our separate existence.
155
<PAGE>
U.S. FEDERAL INCOME TAX
CONSEQUENCES OF THE EXCHANGE OFFER
Exchange of Notes
The following summary describes the material U.S. federal income tax
consequences of the exchange offer. The exchange of outstanding notes for
exchange notes in the exchange offer will not constitute a taxable event to
holders. Consequently, no gain or loss will be recognized by a holder upon
receipt of an exchange note, the holding period of the exchange note will
include the holding period the outstanding note and the basis of the exchange
note will be the same as the basis of the outstanding note immediately before
the exchange.
In any event, persons considering the exchange of outstanding notes for
exchange notes should consult their own tax advisors concerning the United
States federal income tax consequences in light of their particular situations
as well as any consequences arising under the laws of any other taxing
jurisdiction.
156
<PAGE>
PLAN OF DISTRIBUTION
Until , 2000, 90 days after the date of this prospectus, all
dealers effecting transactions in the exchange notes, whether or not
participating in this distribution, may be required to deliver a prospectus.
This is in addition to the obligation of dealers to deliver a prospectus when
acting as underwriters and with respect to their unsold allotments or
subscriptions.
Each broker-dealer that receives exchange notes for its own account pursuant
to the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of such exchange notes. This prospectus, as it may
be amended or supplemented, may be used by a broker-dealer in connection with
resales of exchange notes received in exchange for outstanding notes where such
outstanding notes were acquired as a result of market-making activities or
other trading activities. Port Arthur Finance has agreed that it will make this
prospectus, as amended or supplemented, available to any broker-dealer for use
in connection with any such resale for a period of 120 days from the date on
which the exchange offer is consummated, or such shorter period as will
terminate when all outstanding notes acquired by broker-dealers for their own
accounts as a result of market-making activities or other trading activities
have been exchanged for exchange notes and such exchange notes have been resold
by such broker-dealers. In addition, dealers effecting transactions in the
exchange notes may be required to deliver a prospectus.
Port Arthur Finance will not receive any proceeds from any sale of exchange
notes by broker-dealers. Exchange notes received by broker-dealers for their
own account pursuant to the exchange offer may be sold from time to time in one
or more transactions in the over-the-counter market, in negotiated
transactions, through the writing of options on the exchange notes or a
combination of such methods of resale, at market prices prevailing at the time
of resale, at prices related to such prevailing market prices or negotiated
prices. Any such resale may be made directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer or the purchasers of any exchange
notes. Any broker-dealer that resells exchange notes that were received by it
for its own account pursuant to the exchange offer and any broker or dealer
that participates in a distribution of such exchange notes may be deemed to be
an "underwriter" within the meaning of the Securities Act and any profit on any
such resale of exchange notes and any commissions or concessions received by
any such persons may be deemed to be underwriting compensation under the
Securities Act. The letter of transmittal states that by acknowledging that it
will deliver and by delivering a prospectus, a broker-dealer will not be deemed
to admit that it is an "underwriter" within the meaning of the Securities Act.
For a period of 120 days from the date on which the exchange offer is
consummated, or such shorter period as will terminate when all outstanding
notes acquired by broker-dealers for their own accounts as a result of market-
making activities or other trading activities have been exchanged for exchange
notes and such exchange notes have been resold by such broker-dealers, Port
Arthur Finance will promptly send additional copies of this prospectus and any
amendment or supplement to this prospectus to any broker-dealer that requests
such documents in the letter of transmittal. Port Arthur Finance has agreed to
pay all expenses incident to the exchange offer other than commissions or
concessions of any brokers or dealers and the fees of any counsel or other
advisors or experts retained by the holders of outstanding notes, except as
expressly set forth in the registration rights agreement, and will indemnify
the holders of outstanding notes, including any broker-dealers, against
specified liabilities, including liabilities under the Securities Act. In the
event of a shelf registration, Port Arthur Finance has agreed to pay the
expenses of one firm of counsel designated by the holders of notes covered by
the shelf registration.
If you are an affiliate of Port Arthur Finance or are engaged in, or intend
to engage in, or have an agreement or understanding to participate in, a
distribution of the exchange notes, you cannot rely on the applicable
interpretations of the Securities and Exchange Commission and you must comply
with the registration requirements of the Securities Act of 1933 in connection
with any resale transaction.
157
<PAGE>
LEGAL MATTERS
Our counsel, Simpson Thacher & Bartlett, New York, New York, will issue an
opinion regarding the validity of the notes and other specified legal matters.
Simpson Thacher & Bartlett provides legal services to Clark Refining
Holdings, Clark USA and Clark Refining & Marketing, as well as Blackstone and
its affiliates, on a regular basis. In addition, Simpson Thacher & Bartlett
provided legal services to these parties in connection with some of the
transactions described in this prospectus. Some partners of Simpson Thacher &
Bartlett and related persons have an indirect interest in less than 1% of the
common stock of Clark Refining Holdings.
EXPERTS
The consolidated financial statements of Port Arthur Coker Company L.P. and
Subsidiary as of December 31, 1999 and for the period from May 4, 1999,
inception, to December 31, 1999 included in this registration statement have
been audited by Deloitte & Touche LLP, as stated in their report, which is
included elsewhere in this prospectus, and has been so included in reliance
upon the report of such firm given upon their authority as experts in
accounting and auditing.
The consolidated financial statements of Sabine River Holding Corp. and
Subsidiaries as of December 31, 1999 and for the period from May 4, 1999,
inception, to December 31, 1999 included in this registration statement have
been audited by Deloitte & Touche LLP, as stated in their report, which is
included elsewhere in this prospectus, and has been so included in reliance
upon the report of such firm given upon their authority as experts in
accounting and auditing.
The consolidated financial statements of Clark Refining & Marketing as of and
for the years ended December 31, 1997 and 1998 included in Annex A to this
prospectus have been audited by Deloitte & Touche LLP, independent auditors, as
stated in their report, which are also included in Annex A to this prospectus,
and have been so included in reliance upon the report of such firm upon their
authority as experts in accounting and auditing.
With respect to the unaudited interim financial information of Clark Refining
and Marketing for the three and nine month periods ended September 30, 1998 and
1999 which is included in Annex A to this prospectus, Deloitte & Touche LLP
have applied limited procedures in accordance with professional standards for a
review of such information. However, as stated in their reports included in
Clark Refining & Marketing's Quarterly Reports on Form 10Q/A for the quarter
ended September 30, 1999 and included in Annex A to this prospectus, they did
not audit and they do not express an opinion on that interim financial
information. Accordingly, the degree of reliance on their reports on such
information should be restricted in light of the limited nature of the review
procedures applied. Deloitte & Touche LLP are not subject to the liability
provisions of Section 11 of the Securities Act of 1933 for their reports on the
unaudited interim financial information because those reports are not "reports"
or a "part" of the registration statement prepared or certified by an
accountant within the meaning of Sections 7 and 11 of the Act.
The consolidated financial statements of Clark Refining & Marketing for the
year ended December 31, 1996 included in Annex A to this prospectus have been
audited by PricewaterhouseCoopers LLP which was formed on July 1, 1998, by the
merger of Coopers & Lybrand L.L.P. and Price Waterhouse LLP, independent
auditors, as stated in their reports, which are included in Annex A to this
prospectus, and have been so included and incorporated in reliance upon the
report of such firm given upon their authority as experts in accounting and
auditing.
Neither our independent auditors, nor any other independent accountants, have
compiled, examined or performed any procedures with respect to our or Purvin &
Gertz's estimates regarding the coker project contained herein, nor have they
expressed any opinion or any other form of assurance on such information or its
achievability, and assume no responsibility for, and disclaim any association
with, the aforementioned estimates.
158
<PAGE>
INDEPENDENT ENGINEER
Purvin & Gertz prepared the independent engineer's report included as Annex B
to this prospectus. We include this report in this prospectus in reliance upon
Purvin & Gertz's authority as a leading consulting and engineering firm
experienced in review of the design, development and operation of petroleum
refinery projects. You should read this report in its entirety for information
with respect to our coker project and the related matters discussed this
report.
INDEPENDENT MARKET CONSULTANT
Purvin & Gertz prepared the crude oil and refined products market report
included as Annex C to this prospectus. We include this report in this
prospectus in reliance upon Purvin & Gertz's authority as a consultant in
evaluation of Maya and other refinery feedstock markets and related matters.
You should read this report in its entirety for information with respect to our
coker project and the related matters discussed this report.
AVAILABLE INFORMATION
We have filed with the Commission a registration statement on Form S-4 under
the Securities Act with respect to the exchange notes being offered by this
prospectus. This prospectus, which forms a part of the registration statement,
does not contain all of the information set forth in the registration
statement. You should refer to the registration statement for further
information. Statements contained in this prospectus as to the contents of any
contract or other document are not necessarily complete, however, we believe
that all material terms of these documents and contracts are accurately
summarized in this prospectus.
We are not currently required by the Exchange Act to file reports with the
U.S. Securities and Exchange Commission. At a future date, however, we may be
required to file reports with the Commission. Prior to any date on which we are
required to file such reports, we will provide without charge, upon written
request of a holder of a note or a prospective investor, a copy of such
information as is required by Rule 144A to enable resales of the notes to be
made in compliance with Rule 144A unless, at the time of such request, we are
subject to the reporting requirements of Section 13 or 15(d) of the Exchange
Act. Any such request will be subject to the confidentiality provisions
referred to below. Written requests for such information should be addressed to
the Corporate Secretary at our executive offices located at 1801 S. Gulfway
Drive, Office No. 36, Port Arthur, Texas 77640. Each prospective investor
agrees to keep confidential the various documents and all written information
that from time to time have been or will be disclosed to it concerning us and
our coker project, including without limitation, any of the financial
statements and information disclosed hereunder, and agrees not to disclose any
portion of the same to any person.
Clark Refining & Marketing, Occidental, Foster Wheeler Corporation, Air
Products and PEMEX are subject to the informational requirements of the
Exchange Act, and in accordance with the Exchange Act have filed reports and
other information with the Commission. Such reports and other information can
be inspected and copied at the public reference facilities maintained by the
Commission at Judiciary Plaza, 450 Fifth Street, NW, Room 1024, Washington,
D.C. 20549. Copies of such materials may be obtained by mail from the Public
Reference Section of the Commission at 450 Fifth Street, NW, Washington, D.C.
20549. The Commission maintains a Web site at http://www.sec.gov that contains
reports and information statements and other information regarding registrants,
such as Clark Refining & Marketing, Occidental, Foster Wheeler Corporation and
Air Products, that file electronically with the Commission.
In addition, we have attached as Annex A to this prospectus additional
information regarding Clark Refining & Marketing. You are urged to read such
information in its entirety.
159
<PAGE>
GLOSSARY OF TECHNICAL TERMS
"API gravity": a method of differentiating crude oil quality which is closely
correlated to product yields. In other words, the processing of a crude oil
with a higher API gravity should result in increased yields of higher valued
products when compared to the processing of a crude oil with a lower API
gravity.
"backcast": a financial modeling method used by Purvin & Gertz in its report,
which is included in this prospectus as Annex B, to analyze expected cash
flows, debt service coverage ratios and other financial results of our coker
project using a price set for crude oil and refined products based on actual
prices for a representative time period in the recent past.
"barrels per stream day" or "barrels per day": a measurement of the capacity
of a particular processing unit to process feedstocks on a daily basis. A
barrel is equal to forty-two gallons. Barrels per stream day is based on the
number of days a unit is operating while per day is based on calendar days.
"coker gross margin": the difference or "spread" between the market price of
intermediate refined products from operation of our coking unit and the cost of
producing feedstocks for the coking unit.
"configuration": this term is described under the caption "The U.S. Petroleum
Refining Industry and Refinery Configuration--Refinery Configuration" in this
prospectus and refers to the number, types and sequencing of processing units
at a refinery.
"conversion capacity": a measure of the capability of a refinery or a group
of refineries to upgrade crude oil into lighter refined products, such as
gasoline, jet and diesel fuel.
"crude oil distillation capacity": a measure of the capability of a refinery
or a group of refineries to process crude oil into refined products. Generally
used to described overall world-wide or country-specific capacity to process
crude oil.
"crude unit": this processing unit is described in the sections captioned
"Prospectus Summary--Overview" and "Our Coker Project--Clark Refining &
Marketing's Portion of the Refinery Upgrade Project" in this prospectus.
"delayed coking unit" or "coker": this processing unit is described in the
sections captioned "Prospectus Summary--Overview" and "Our Coker Project--Our
Portion of the Refinery Upgrade Project" in this prospectus.
"distillation": the refining process of separating crude oil components by
heating and subsequent cooling. The simplest and least costly refining process.
"distillates": a term for the products of distillation that is commonly used
to refer to diesel fuel, jet fuel and home heating oil.
"feedstocks": the raw materials needed for a refinery processing unit to
produce a particular refined product.
"final or finished refined products": petroleum products for which a
commercial market exists without need for additional refining.
"fuel oil" or "distillate fuel oil": lighter more valuable and marketable
fuel oils, as distinguished from residual fuel oil. Fuel oils are generally
used for diesel fuel and residential heating and are classified in grades,
called number 1, 2, 3, 4, or 6 fuel oil.
"heavy/light differential": the dollar per barrel price difference between
heavy sour crude oil and light sweet crude oil, which is used as an indication
of the profitability advantage of a heavy coking refinery as described in this
prospectus under the caption "The U.S. Petroleum Refining Industry and Refinery
Configuration--Heavy/Light Differential."
160
<PAGE>
"heavy sour crude oil": crude oil with a lower API gravity that contains
significant impurities and sulfur.
"hydrotreater": this processing unit is described in the sections captioned
"Prospectus Summary--Overview" and "Our Coker Project--Clark Refining &
Marketing's Portion of the Refinery Upgrade Project" in this prospectus.
"intermediate refined products": petroleum products that are generally
considered to need additional refining prior to becoming commercially saleable.
"light sweet crude oil": crude oil with a higher API gravity that is
substantially free of impurities and sulfur.
"Maya": the type of heavy sour crude oil available under our long-term crude
oil supply agreement and the type of crude oil used by Purvin & Gertz as a
proxy for all heavy sour crude oils when calculating the heavy/light
differential.
"refined products": petroleum products that result from the refining process.
"refining": the process of receiving crude oil, breaking it down into various
components and blending the components into useful products.
"refining margin": the difference or "spread" between market prices for
refined products that a refinery produces and the cost of the crude oil and
other feedstocks processed by a refinery.
"residue" or "residual fuel oil": the substance that is leftover after the
refining process has extracted the desirable, and more marketable, products
such as gasoline, kerosene and distillate fuel oil. Residual fuel oil is used
mainly for heavy industrial fuel and in the manufacturing of asphalt.
"Solomon complexity rating": an oil industry standard for comparing
refineries based on the complexity of their configurations. A more "complex"
refinery such as one with conversion capacity generally produces a more
valuable mix of products.
"spot market": a market for purchase and sale of crude oil or other oil
products on a short-term or one-time basis.
"throughput capacity": a measurement of the capacity of a refinery or a
particular processing unit at a refinery to process crude oil or another
feedstock, generally expressed in barrels per day.
"sulfur complex": these processing units are described in the sections
captioned "Prospectus Summary--Overview" and "Our Coker Project--Our Portion of
the Refinery Upgrade Project" in this prospectus.
"vacuum gas oil hydrocracker" or "hydrocracker": this processing unit is
described in the section captioned "Prospectus Summary--Overview" and "Our
Coker Project--Our Portion of the Refinery Upgrade Project" in this prospectus.
"vacuum tower bottoms": the residue leftover from the processing of crude oil
by the refinery's crude vacuum distillation unit and the feedstock for our new
coker.
"West Texas Intermediate": a common type of light sweet crude oil which is
used by Purvin & Gertz as a proxy for all light sweet crude oils when
calculating the heavy/light differential.
161
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Port Arthur Coker Company L.P. and Subsidiary (A Development Stage
Company)
Annual Financial Statements
Independent Auditors' Report ........................................... F-2
Consolidated Balance Sheet as of December 31, 1999 ..................... F-3
Consolidated Statement of Operations for the period from May 4
(inception) to December 31, 1999....................................... F-4
Consolidated Statement of Cash Flows for the period from May 4
(inception) to December 31, 1999....................................... F-5
Consolidated Statement of Partners' Capital............................. F-6
Notes to Consolidated Financial Statements.............................. F-7
Sabine River Holdings Corp. and Subsidiaries
Annual Financial Statements
Independent Auditors' Report............................................ F-13
Consolidated Balance Sheet as of December 31, 1999...................... F-14
Consolidated Statement of Operations for the period from May 4
(inception) to December 31, 1999....................................... F-15
Consolidated Statement of Cash Flows for the period from May 4
(inception) to December 31, 1999 ...................................... F-16
Consolidated Statement of Stockholders' Equity.......................... F-17
Notes to Consolidated Financial Statements.............................. F-18
</TABLE>
F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Sabine River Holding Corp.,
as general partner of Port Arthur Coker Company L.P.
Port Arthur, Texas
We have audited the accompanying consolidated balance sheet of Port Arthur
Coker Company L.P. and Subsidiary (a development stage company) as of December
31, 1999, and the related consolidated statements of operations, partners'
capital and cash flows 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 audit.
We conducted our audit 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 audit provides 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 and Subsidiary as of
December 31, 1999, and the results of their operations and their cash flows 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
March 2, 2000
F-2
<PAGE>
PORT ARTHUR COKER COMPANY L.P. AND SUBSIDIARY
(A Development Stage Company)
Consolidated Balance Sheet
(dollars in thousands)
<TABLE>
<CAPTION>
Reference December 31,
Note 1999
--------- ------------
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash................................................... $ 1
Receivable from affiliate.............................. 10 90
Prepaid expenses....................................... 4 845
--------
Total current assets.................................. 936
CONSTRUCTION IN PROGRESS................................ 2 378,411
CASH AND CASH EQUIVALENTS RESTRICTED FOR CAPITAL
ADDITIONS.............................................. 2,5 46,657
OTHER ASSETS............................................ 6 20,575
--------
$446,579
========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable....................................... $ 28,145
Accrued expenses and other............................. 14,721
Payables with affiliates............................... 10 497
--------
Total current liabilities............................. 43,363
LONG-TERM DEBT.......................................... 7 360,000
COMMITMENTS AND CONTINGENCIES........................... 10 --
PARTNERS' CAPITAL
Partners' capital commitments.......................... 8 134,950
Capital contributions receivable....................... 8 (77,830)
--------
Partners' capital contributed.......................... 57,120
Deficit accumulated during development stage........... (13,904)
--------
Total partners' capital............................... 43,216
--------
$446,579
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE>
PORT ARTHUR COKER COMPANY L.P. AND SUBSIDIARY
(A Development Stage Company)
Consolidated Statement of Operations
(dollars in thousands)
<TABLE>
<CAPTION>
For the period from
May 4,
Reference (inception) to
Note December 31, 1999
--------- -------------------
<S> <C> <C>
EXPENSES:
General and administrative expenses............... $ 3,149
INTEREST AND FINANCE COSTS, NET.................... 9 10,755
--------
NET LOSS........................................... $(13,904)
========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-4
<PAGE>
PORT ARTHUR COKER COMPANY L.P. AND SUBSIDIARY
(A Development Stage Company)
Consolidated Statement of Cash Flows
(dollars in thousands)
<TABLE>
<CAPTION>
For the
period from
May 4,
(inception)
to
December 31,
1999
------------
<S> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss........................................................... $ (13,904)
Amortization of deferred financing costs........................... 534
Cash provided by (used in) working capital
Prepaid expenses and affiliate receivables/payables............... (438)
Accounts payable and accrued expenses............................. 42,866
---------
Net cash provided by operating activities........................ 29,058
---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for construction in progress......................... (380,585)
Cash restricted for investment in capital additions............... (46,657)
---------
Net cash used in investing activities............................. (427,242)
---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt.......................... 360,000
Capital contributions............................................. 57,120
Deferred financing costs.......................................... (18,935)
---------
Net cash provided by financing costs.............................. 398,185
---------
NET INCREASE IN CASH............................................... 1
CASH, beginning of period.......................................... --
---------
CASH, end of period................................................ $ 1
=========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-5
<PAGE>
Port Arthur Coker Company and Subsidiary (A Development Stage Company)
Consolidated Statement of Change in Partners' Capital
(dollars in thousands)
<TABLE>
<CAPTION>
Sabrine Neches
River River
Holding Holding
Corp. Corp. Total
------- -------- --------
<S> <C> <C> <C>
Partners' capital contributed........................ $ 571 $56,549 $57,120
Deficit accumulated during development stage......... (139) (13,765) (13,904)
----- -------- --------
Balance at December 31, 1999......................... $432 $42,784 $43,216
===== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-6
<PAGE>
PORT ARTHUR COKER COMPANY L.P. AND SUBSIDIARY
(A Development Stage Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the period from May 4 (inception) to December 31, 1999
1. Nature of Business
Port Arthur Coker Company L.P. (the "Company") was formed as a Delaware
limited partnership on May 4, 1999. The Company was formed to construct, own,
operate and finance a new 80,000 barrel per stream day delayed coker unit, a
35,000 barrel per stream day hydrocracker and a 417 long tons per day sulfur
complex and related assets (the "Coker Project") at the Port Arthur, Texas
refinery of an affiliate, Clark Refining & Marketing, Inc ("Clark Refining &
Marketing"). Port Arthur Coker Company L.P. is owned 1% by its general partner,
Sabine River Holding Corp. ("Sabine River"), and 99% by its limited partner,
Neches River Holding Corp. ("Neches River"). Both partners were incorporated in
Delaware in May 1999. Sabine River is owned 90% by Clark Refining Holdings Inc.
("Clark Refining Holdings") and 10% by Occidental Petroleum Corporation
("Occidental"). Neches River is owned 100% by Sabine River. After giving effect
to anticipated equity contributions to be made in connection with the funding
of the projects, Clark Refining Holdings will be owned, indirectly through
subsidiaries, by Blackstone Capital Partners III Merchant Banking Fund L.P. and
its affiliates ("Blackstone") with an approximately 82% interest, and by
Occidental with an approximately 17% interest. The Company is an affiliate of
Clark Refining & Marketing because Clark Refining Holdings owns 100% of the
capital stock of Clark USA, Inc., which in turn owns 100% of the capital stock
of Clark Refining & Marketing.
As of the date hereof, Port Arthur Coker Company and its subsidiary have not
conducted any operations and are in the development stage. In order to fund the
Company's Coker Project, in August 1999 the Company, through a wholly-owned
subsidiary, Port Arthur Finance Corp. ("Port Arthur Finance"), issued $255
million in notes, entered into a $325 million secured construction and term
loan facility, obtained a $75 million secured working capital facility and
entered into equity subscription agreements totaling $135 million (see Note 7--
Long-Term Debt). Port Arthur Finance, a Delaware holding company, was formed on
May 4, 1999. Port Arthur Finance's organizational documents only allow it to
engage in activities related to issuing notes and borrowing under bank credit
facilities in connection with the initial financing of the Company, and
remitting the proceeds thereof to the Company. In issuing the notes and
borrowing under the bank credit facilities, Port Arthur Finance is acting as an
agent of the Company.
In March 1998, Clark Refining & Marketing announced that it had entered into
a long-term crude oil supply agreement with P.M.I. Comercio Internacional, S.A.
de C.V. ("PMI"), an affiliate of Petroleos Mexicanos, the Mexican state oil
company. The contract provided Clark Refining & Marketing with the foundation
necessary to continue developing a project to upgrade its Port Arthur, Texas
refinery to process primarily lower-cost, heavy sour crude oil. The project
includes the construction of additional coking and hydrocracking capability,
and the expansion of crude unit capacity to approximately 250,000 barrels per
day. The oil supply agreement with PMI and the construction work-in-progress
related to the new processing units were transferred at fair market value to
the Company in the third quarter of 1999. In connection with the project, Clark
Refining & Marketing will lease certain existing processing units of Clark
Refining & Marketing to the Company on fair market terms and, pursuant to this
lease, will be obligated to make certain modifications, infrastructure
improvements and incur certain development costs during 1999 and 2000 at an
estimated cost up to $120 million. To secure this commitment, Clark Refining &
Marketing posted a letter of credit in the amount of $97 million at the
closing. As of December 31, 1999, Clark Refining & Marketing had expended
approximately $51 million towards this commitment. In addition, the Company
entered into agreements with Clark Refining & Marketing pursuant to which Clark
Refining & Marketing will provide certain operating, maintenance and other
services and will purchase the output from the new coking and hydrocracking
equipment for further processing into finished products. The Company also
entered into agreements under which the Company will process certain
hydrocarbon streams owned by Clark Refining & Marketing.
F-7
<PAGE>
2. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the Company's
wholly-owned subsidiary Port Arthur Finance.
All significant intercompany transactions have been eliminated from the
consolidated financial statements.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the dates of financial statements and the
reported amount of revenues and expenses during the reporting period. 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. Cash and cash equivalents as of December 31,
1999, approximated fair value.
Construction in Progress
All additions are recorded at cost and are currently included in Construction
in Progress because the Coker Project is under construction. When the assets
are in operation, depreciation of plant and equipment will be computed using
the straight-line method over the estimated useful lives of the assets or group
of assets. The Company capitalizes the interest cost associated with major
construction projects based on the effective interest rate on aggregate
borrowings applied to expenditures from date of project inception to start-up.
Expenditures for maintenance and repairs are expensed. Major replacements and
additions are capitalized. Gains and losses on assets depreciated on an
individual basis are reflected in the results from operations.
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.
Environmental Costs
Environmental liabilities are recorded when environmental assessments and/or
remedial efforts are probable and can be reasonably estimated.
Environmental expenditures are expensed or capitalized depending upon their
future economic benefit. Costs that improve a property as compared with the
condition of the property when originally constructed or acquired and costs
that prevent future environmental contamination are capitalized. Costs that
return a property to its condition at the time of acquisition or original
construction are expensed.
Income Taxes
The Company is classified as a partnership for U.S. federal income tax
purposes and, accordingly, does not pay federal income tax. The 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 the Company.
Port Arthur Finance files a separate U.S. federal income tax return and
computes its provision on a separate company basis. 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
F-8
<PAGE>
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.
3. Accounting Changes
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This statement establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The Company is required to adopt this statement effective January
1, 2001. SFAS No. 133 will require the Company to record all derivatives on the
balance sheet at fair value. Changes in derivative fair value will either be
recognized in earnings as offsets to the changes in fair value of related
hedged assets, liabilities, and firm commitments or, for forecasted
transactions, deferred and recorded as a component of comprehensive income
until the hedged
transactions occur and are recognized in earnings. The ineffective portion of a
hedging derivative's change in fair value will be recognized in earnings
immediately. The Company is currently evaluating when it will adopt this
standard and the impact of the standard on the Company. The impact of SFAS No.
133 will depend on a variety of factors, including the future level of hedging
activity, the types of hedging instruments used, and the effectiveness of such
instruments.
4. Prepaid Expenses
As of December 31, 1999, prepaid expenses consisted of the amounts expended
in 1999 for several insurance policies. These amounts are being amortized over
the lives of the policies.
5. Cash and Cash Equivalents Restricted for Capital Additions
Pursuant to the notes issued by Port Arthur Finance on behalf of the Company,
all proceeds from the notes are restricted for use in the construction of new
operating units.
6. Other Assets
<TABLE>
<CAPTION>
December 31,
1999
--------------
(in thousands)
<S> <C>
Other Assets consisted of the following:
Deferred financing costs........................................ $18,400
Environmental permits........................................... 1,418
P.M.I. long-term crude oil supply agreement..................... 757
-------
$20,575
=======
</TABLE>
The Company incurred deferred financing costs of $18.9 million associated
with the issuance of the $255.0 million in notes and having entered into the
$325.0 million secured construction and term loan facility. Amortization of
deferred financing costs for the period May 4, 1999 (inception) to December 31,
1999 was $0.5 million and is included in "Interest and finance costs, net".
The P.M.I. long-term crude oil supply agreement and environmental permits
were purchased from Clark Refining & Marketing. When the Coker Project is
operational, the Company will amortize the costs over the life of the
agreements.
F-9
<PAGE>
7. Long-Term Debt
Long-term debt was a follows:
<TABLE>
<CAPTION>
December 31,
1999
------------
(dollars in
thousands)
<S> <C>
Secured Construction and Term Loan Facility........................ $105,000
12 1/2% Senior Secured Notes due January 15, 2009
(12 1/2% Senior Notes)............................................. 255,000
--------
$360,000
========
</TABLE>
The 12 1/2% Senior Notes were issued by Port Arthur Finance in August 1999 on
behalf of the Company at par and are secured by substantially all of the assets
of the Company. The Company is required to pay a portion of the principal of
the notes on a set schedule on each January 15 and July 15, commencing July 15,
2002. The 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 75 basis points.
The Company entered into a $325 million secured construction and term loan
facility to be provided by commercial banks and institutional lenders. The
construction and term loan was split into a Tranche A of $225 million with a
term of 7.5 years and a Tranche B of $100 million with a term of 8 years. Under
specified circumstances, the aggregate amount of the construction and term loan
facility may be reallocated between the tranches with the Company's consent,
which may not be unreasonably withheld. In addition, the Company obtained a $75
million secured working capital facility from commercial banks, which banks
included some of the same commercial banks that provide the construction and
term loan facility. In February 2000, our $75 million secured working capital
facility was reduced to $35 million. The $40 million reduction, a portion of
which had been outstanding in the form of a letter of credit to P.M.I. Comercio
International to secure against a default by us under our long term oil supply
agreement, was replaced by an insurance policy under which an affiliate of
American International Group agreed to insure P.M.I. Comercio International
against our default under the long term oil supply agreement up to a maximum
liability of $40 million. This affiliate of American International Group is
treated as a bank senior lender under the common security agreement.
The 12 1/2% Senior Notes indenture and construction and term loan facility
credit agreement contains certain restrictive covenants including limitations
on distributions to our owners from our distribution account, limitations on
Blackstone disposing of any equity interest in Clark Refining Holdings,
limitations on Clark Refining Holdings disposing of any equity interest in
Clark Refining & Marketing, the Port Arthur Refinery or the Company and
limitation on incurring additional senior debt. The Company was required to
provide a debt service reserve arrangement which was provided through an
insurance product that will be replaced with a cash funded reserve account from
available cash flow from operations.
Interest payments are due semiannually on January 15, and July 15, for both
the 12 1/2% Senior Notes and the Secured Construction and Term Loan Facility.
The scheduled maturities of long-term debt during the next five years are (in
millions): 1999, 2000 and 2001--$0; 2002--$5.3; 2003--$15.8; 2004 and
thereafter--$338.9.
8. Capital Contributions Receivable
In August 1999, Blackstone and Occidental signed capital contribution
agreements totaling $135 million. Blackstone agreed to contribute $121.5
million, and Occidental agreed to contribute $13.5 million to the Company. As
of December 31, 1999, Blackstone and Occidental contributed approximately $51.4
million and $5.7 million, respectively, of their commitments. The remaining
$77.8 million was recorded as contributions receivable. The contractual
arrangements with Blackstone and Occidental provide that the aggregate $135
million equity commitment will be funded pro rata with the funding of the notes
and bank term debt, so that at
F-10
<PAGE>
the time of each advance of debt and equity to pay construction costs the
amount funded will be approximately 65% debt and 35% equity. It is expected
that the entire $135 million equity commitment will be funded by March 2001.
The obligations of Blackstone and Occidental to fund their equity commitments
are absolute, irrevocable and unconditional so long as a pro rata portion of
bank term debt is funded at the same time. The obligation of Blackstone to fund
its outstanding equity commitment may be assumed by a third party if Blackstone
transfers its equity interest in Clark Refining Holdings to such third party
and either (i) such third party is rated investment grade by both S&P and
Moody's after giving effect to such transfer or (ii) a majority of lenders
under the Secured Construction and Term Loan Facility have consented to such
transfer and either a majority of holders of 12 1/2% Senior Notes have
consented or the Company has received a ratings reaffirmation from both rating
agencies with respect to the 12 1/2% Senior Notes.
9. Interest and Finance Costs, Net
Interest and Finance Costs, Net were as follows:
<TABLE>
<CAPTION>
For the period
May 4 (inception)
to
December 31, 1999
-----------------
(dollars in
thousands)
<S> <C>
Interest expense.............................................. $ 15,565
Finance expense............................................... 10,658
Capitalized interest.......................................... (13,798)
Interest income............................................... (1,670)
--------
Interest and Finance Costs, Net............................... $ 10,755
========
</TABLE>
Finance expense included costs related to the Company's working capital
facility as well as insurance costs for working capital, a debt service reserve
arrangement and a P.M.I. crude oil supply arrangement.
10. Commitments and Contingencies
In July 1999, the Company entered into a contract for the engineering,
procurement and construction of the Company's Coker Project with Foster Wheeler
USA. Under this construction contract, Foster Wheeler USA will continue to
engineer, design, procure equipment for, construct, test and oversee startup of
the Coker Project and integrate the Coker Project with the Port Arthur refinery
of Clark Refining & Marketing, Inc. Under the construction contract, the
Company will pay Foster Wheeler USA a fixed price of approximately $544 million
of which $157.1 million was credited to the Company for amounts Clark Refining
& Marketing had already paid Foster Wheeler USA for work performed on the Coker
Project prior to August 1999. The Company purchased this work in progress from
Clark Refining & Marketing when the financings were consummated in August 1999.
The Company and Foster Wheeler USA have the ability to initiate changes to work
under the contract that may effect the final total price paid. Changes in
excess of $0.5 million individually or $5.0 million in the aggregate must be
approved by the project's independent engineer. The contract has provisions
whereby Foster Wheeler will pay the Company up to $145 million in damages for
delays in achieving mechanical completion or guaranteed reliability, based on a
defined formula. The Company is required to pay Foster Wheeler USA an early
completion bonus of up to $6 million if mechanical completion is achieved prior
to November 1, 2000. The Company can terminate the contract with Foster Wheeler
USA at any time upon written notice, at which time it will be obligated to pay
actual project costs to the date of termination, other costs related to
demobilizing, canceling subcontractors or withdrawing from the project site.
Foster Wheeler USA cannot terminate the contract unless the Company defaults on
required payments under the contract.
In August 1999, the Company entered into agreements with Clark Refining &
Marketing pursuant to which the Company will receive certain operating,
maintenance, and other services from Clark Refining & Marketing and will sell,
at market prices, the output from the new coking and hydrocracking equipment to
Clark Refining & Marketing for further processing into finished products. The
Company also entered into agreements under which it will process certain
hydrocarbon streams owned by Clark Refining & Marketing. In
F-11
<PAGE>
addition, the Company entered into lease agreements under which it will lease
Clark Refining & Marketing's crude unit, vacuum tower, two distillate
hydrotreaters, and a naphtha hydrotreater at the Port Arthur refinery as well
as the site where the Company's new processing units are located. The Company
will receive and pay compensation at what it believes to approximate fair
market value under these agreements. At December 31, 1999, the Company had a
net outstanding payable balance of $0.4 million to Clark Refining & Marketing
consisting of a payable of $0.5 million for services under these agreements and
fees paid by Clark Refining & Marketing on the Company's behalf and a $0.1
million receivable for the overpayment of such services in a prior period.
In August 1999, the Company purchased a long-term crude oil supply agreement
with PMI from Clark Refining & Marketing for approximately $0.8 million. The
contract includes a gross margin support mechanism designed to provide a
minimum average coker gross margin over its initial term. Pursuant to the terms
of the contract, PMI will supply to the Company Maya crude oil for a price
based on published market prices for crude and refined products, as defined in
the contract. The contract extends for eight years from the later of the start-
up date of the coker, the schedule completion date of January 2001 or the
guarantee date of July 2001. The completion date is the date the coker meets
prescribed operating performance. If the completion date extends beyond January
2001, the Company must pay P.M.I $400,000 per month for the first six months of
delay and $200,000 per month for up to an additional six months of delay
thereafter to extend the completion date or they may terminate the contract.
The Company may terminate the contract after paying PMI a termination payment
of approximately $170,000 per month after August 31, 1998 plus actual damages
that PMI has suffered. The Company does not currently anticipate the Coker
Project completion date being extended beyond January 2001.
In August 1999, the Company entered into an agreement with Air Products and
Chemicals, Inc. ("Air Products") to supply the hydrogen needs of the Coker
Project. Air Products will also supply steam and electricity to the Company
under this agreement. Prices under the contract are based on market prices at
the time of the contract, subject to adjustment according to a formula based on
inflation indices. Air Products will be required to pay the Company liquidated
damages of up to $1.2 million if the plant fails to be ready for commercial
operation on or before December 2000 and the Company will be required to pay
Air Products liquidated damages of up to $1.2 million if the Company is unable
to start-up the coker for initial operations prior to December 2000. The
Company does not currently anticipate the Coker Project initial start-up date
being extended beyond December 2000.
Environmental laws typically provide that the owner 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. The Port Arthur
refinery is located on a contaminated site. Under the 1994 purchase agreement
between Clark Refining & Marketing and Chevron Products USA relating to the
Port Arthur refinery, Chevron retained environmental remediation obligations
regarding pre-closing contamination at over 97% of the refinery site. Clark
Refining & Marketing assumed responsibility for any remediation that is
required in and under the remaining 3% of the refinery site, which consists of
specified areas that extend 25 to 100 feet from active operating units,
including soil and groundwater. Clark Refining & Marketing has estimated its
liability for remediation of soil and groundwater soil in these areas at $27
million. Chevron is obligated to remediate the contamination is the areas for
which it has retained responsibility as and when required by law, in accordance
with remediation plans negotiated by Chevron and the applicable federal and
state agencies.
No part of our Coker Project site is located within the portion of the Port
Arthur refinery site for which Chevron retains environmental remediation
obligations. We have estimated remedial costs relating to our Coker Project
site, which surpasses 50 acres of the total Port Arthur refinery site surface
area, at $1.6 million. Clark Refining & Marketing has agreed to retain
liability regarding contamination existing at the Coker Project site and has
indemnified the Company against such liabilities; therefore, no such liability
has been recorded at the Company. However, if Clark Refining & Marketing does
not fulfill its remediation obligations, the Company could incur substantial
additional costs in remediating the contamination.
F-12
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Sabine River Holding Corp.
We have audited the accompanying consolidated balance sheet of Sabine River
Holding Corp. and Subsidiaries as of December 31, 1999, and the related
consolidated statements of operations, stockholders' equity and cash flows 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 audit.
We conducted our audit 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 audit provides 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 and Subsidiaries as of
December 31, 1999, and the results of their operations and their cash flows 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
March 2, 2000
F-13
<PAGE>
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
Consolidated Balance Sheet
(dollars in thousands)
<TABLE>
<CAPTION>
Reference December 31,
Note 1999
--------- ------------
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash................................................... $ 51
Receivable from affiliate.............................. 10 90
Prepaid expenses....................................... 4 845
--------
Total current assets.................................. 986
CONSTRUCTION IN PROGRESS................................ 2 378,411
CASH AND CASH EQUIVALENTS RESTRICTED FOR CAPITAL
ADDITIONS.............................................. 2,5 46,657
OTHER ASSETS............................................ 6 20,575
--------
$446,629
========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable....................................... $ 28,145
Accrued expenses and other............................. 14,721
Payables with affiliates............................... 10 497
--------
Total current liabilities............................. 43,363
LONG-TERM DEBT.......................................... 7 360,000
COMMITMENTS AND CONTINGENCIES........................... 10 --
COMMON STOCKHOLDERS' EQUITY
Common stock, $.01 par value, 6,818,182 shares issued.. 68
Capital contribution commitments....................... 134,932
Capital contribution receivable........................ (77,830)
--------
Total paid-in capital................................. 57,102
Retained earnings (deficit)........................... (13,904)
--------
Total common stockholders' equity..................... 43,266
--------
$446,629
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-14
<PAGE>
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
Consolidated Statement of Operations
(dollars in thousands)
<TABLE>
<CAPTION>
For the period from
May 4,
Reference (inception) to
Note December 31, 1999
--------- -------------------
<S> <C> <C>
EXPENSES:
General and administrative expenses............... $ 3,149
INTEREST AND FINANCE COSTS, NET.................... 9 10,755
INCOME TAX PROVISION............................... --
--------
NET LOSS........................................... $(13,904)
========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-15
<PAGE>
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
Consolidated Statement of Cash Flows
(dollars in thousands)
<TABLE>
<CAPTION>
For the
period from
May 4,
(inception)
to
December 31,
1999
------------
<S> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss........................................................... $ (13,904)
Amortization of deferred financing costs........................... 534
Cash provided by (used in) working capital
Prepaid expenses and affiliate receivables/payables............... (438)
Accounts payable and accrued expenses............................. 42,866
---------
Net cash provided by operating activities........................ 29,058
---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for construction in progress......................... (380,585)
Cash restricted for investment in capital additions............... (46,657)
---------
Net cash used in investing activities............................. (427,242)
---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt.......................... 360,000
Equity contributions.............................................. 57,170
Deferred financing costs.......................................... (18,935)
---------
Net cash provided by financing costs.............................. 398,235
---------
NET INCREASE IN CASH............................................... 51
CASH, beginning of period.......................................... --
---------
CASH, end of period................................................ $ 51
=========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-16
<PAGE>
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
(dollars in thousands)
<TABLE>
<CAPTION>
Retained
Common Paid-in Earnings
Stock Capital (Deficit) Total
------ ------- --------- --------
<S> <C> <C> <C> <C>
Balance May 4, 1999......................... $-- $ -- $ -- $ --
Equity contribution....................... 68 57,102 -- 57,170
Net loss.................................. -- -- (13,904) (13,904)
--- ------- -------- --------
Balanced - December 31, 1999................ $68 $57,102 $(13,904) $ 43,266
=== ======= ======== ========
</TABLE>
The accompanying notes are an integral part of these statements.
F-17
<PAGE>
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999
1. Nature of Business
Sabine River Holding Corp., a Delaware holding company, (together with its
subsidiaries, the "Company") was incorporated in May of 1999. The Company was
formed as the 1% general partner of Port Arthur Coker Company L.P. ("Port
Arthur Coker Company"), and as the 100% owner of Neches River Holding Corp.
("Neches River"), which is the 99% limited partner of Port Arthur Coker
Company. Sabine River is owned 90% by Clark Refining Holdings Inc. ("Clark
Refining Holdings") and 10% by Occidental Petroleum Corporation ("Occidental").
After giving effect to anticipated equity contributions to be made in
connection with the funding of the project described below, Clark Refining
Holdings will be owned, indirectly through subsidiaries, by Blackstone Capital
Partners III Merchant Banking Fund L.P. and its affiliates ("Blackstone") with
an approximately 82% interest, and by Occidental with an approximately 17%
interest. The Company is an affiliate of Clark Refining & Marketing, Inc.
("Clark Refining & Marketing") because Clark Refining Holdings owns 100% of the
capital stock of Clark USA, Inc., which in turn owns 100% of the capital stock
of Clark Refining & Marketing.
Port Arthur Coker Company was formed to construct, own, operate and finance a
new 80,000 barrel per stream day delayed coker unit, a 35,000 barrel per stream
day hydrocracker and a 417 long tons per day sulfur complex and related assets
(the "Coker Project") at the Port Arthur, Texas refinery of an affiliate, Clark
Refining & Marketing, Inc. As of the date hereof, Port Arthur Coker Company and
its subsidiary have not conducted any operations and are in the development
stage. In order to fund the Coker Project, in August 1999 the Port Arthur Coker
Company, through a wholly-owned subsidiary, Port Arthur Finance Corp. ("Port
Arthur Finance"), issued $255 million in notes, entered into a $325 million
secured construction and term loan facility, obtained a $75 million secured
working capital facility and entered into equity subscription agreements
totaling $135 million (See Note 7 "Long Term Debt"). Port Arthur Finance, a
Delaware holding company, was formed on May 4, 1999. Port Arthur Finance's
organizational documents only allow it to engage in activities related to
issuing notes and borrowing under bank credit facilities in connection with the
initial financing of the Port Arthur Coker Company, and remitting the proceeds
thereof to the Port Arthur Coker Company. In issuing the notes and borrowing
under the bank credit facilities, Port Arthur Finance is acting as an agent of
the Port Arthur Coker Company. As a stand alone entity, Sabine River Holding
Corp's function consists only as a guarantor of the notes and bank loans issued
by Port Arthur Finance Corporation. Sabine River Holding Corp., as a stand
alone entity, has no material assets, no liabilities, and no operations.
In March 1998, Clark Refining & Marketing announced that it had entered into
a long-term crude oil supply agreement with P.M.I. Comercio Internacional, S.A.
de C.V. ("PMI"), an affiliate of Petroleos Mexicanos, the Mexican state oil
company. The contract provided Clark Refining & Marketing with the foundation
necessary to continue developing a project to upgrade its Port Arthur, Texas
refinery to process primarily lower-cost, heavy sour crude oil. The project
includes the construction of additional coking and hydrocracking capability,
and the expansion of crude unit capacity to approximately 250,000 barrels per
day. The oil supply agreement with PMI and the construction work-in-progress
related to the new processing units were transferred at fair market value to
the Company in the third quarter of 1999. In connection with the project, Clark
Refining & Marketing will lease certain existing processing units of Clark
Refining & Marketing to the Company on fair market terms and, pursuant to this
lease, will be obligated to make certain modifications, infrastructure
improvements and incur certain development costs during 1999 and 2000 at an
estimated cost up to $120 million. To secure this commitment, Clark Refining &
Marketing posted a letter of credit in the amount of $97 million at the
closing. As of December 31, 1999, Clark Refining & Marketing had expended
approximately $51 million towards this commitment. In addition, the Company
entered into agreements with Clark Refining & Marketing pursuant to which Clark
Refining & Marketing will provide certain operating, maintenance and other
services and will purchase the output from the new coking and
F-18
<PAGE>
hydrocracking equipment for further processing into finished products. The
Company also entered into agreements under which the Company will process
certain hydrocarbon streams owned by Clark Refining & Marketing.
2. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the Company's
wholly-owned subsidiary Neches River, and through Neches River's 99% and the
Company's 1% ownership of Port Arthur Coker Company, 100% of Port Arthur
Finance Corp and Port Arthur Coker Company.
All significant intercompany transactions have been eliminated from the
consolidated financial statements.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the dates of financial statements and the
reported amount of revenues and expenses during the reporting period. 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. Cash and cash equivalents as of December 31, 1999
approximated fair value.
Construction in Progress
All additions are recorded at cost and are currently included in Construction
in Progress because the Coker Project is under construction. When the assets
are in operation, depreciation of plant and equipment will be computed using
the straight-line method over the estimated useful lives of the assets or group
of assets. The Company capitalizes the interest cost associated with major
construction projects based on the effective interest rate on aggregate
borrowings applied to expenditures from date of project inception to start-up.
Expenditures for maintenance and repairs are expensed. Major replacements and
additions are capitalized. Gains and losses on assets depreciated on an
individual basis are reflected in the results from operations.
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.
Environmental Costs
Environmental liabilities are recorded when environmental assessments and/or
remedial efforts are probable and can be reasonably estimated.
Environmental expenditures are expensed or capitalized depending upon their
future economic benefit. Costs that improve a property as compared with the
condition of the property when originally constructed or acquired and costs
that prevent future environmental contamination are capitalized. Costs that
return a property to its condition at the time of acquisition or original
construction are expensed.
F-19
<PAGE>
Income Taxes
Sabine River and Neches River file a consolidated U.S. federal income tax
return with Clark Refining Holdings, Inc. but compute their provisions on a
separate company basis. 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. As of December 31, 1999, the valuation allowance of the Company
reduced the net deferred tax asset to zero. In calculating the valuation
allowance, the Company assumed as future taxable income only future reversals
of existing taxable temporary differences and available tax planning
strategies.
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. 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.
3. Accounting Changes
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This statement establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The Company is required to adopt this statement effective January
1, 2001. SFAS No. 133 will require the Company to record all derivatives on the
balance sheet at fair value. Changes in derivative fair value will either be
recognized in earnings as offsets to the changes in fair value of related
hedged assets, liabilities, and firm commitments or, for forecasted
transactions, deferred and recorded as a component of comprehensive income
until the hedged transactions occur and are recognized in earnings. The
ineffective portion of a hedging derivative's change in fair value will be
recognized in earnings immediately. The Company is currently evaluating when it
will adopt this standard and the impact of the standard on the Company. The
impact of SFAS No. 133 will depend on a variety of factors, including the
future level of hedging activity, the types of hedging instruments used, and
the effectiveness of such instruments.
4. Prepaid Expenses and Other Current Assets
As of December 31, 1999, prepaid expenses consisted of the amounts expended
in 1999 for several insurance policies. These amounts are being amortized over
the lives of the policies.
5. Cash and Cash Equivalents Restricted for Capital Additions
Pursuant to the notes issued by Port Arthur Finance on behalf of the Company,
all proceeds from the notes are restricted for use in the construction of new
operating units.
F-20
<PAGE>
6. Other Assets
Other assets consisted of the following:
<TABLE>
<CAPTION>
December 31,
1999
--------------
(in thousands)
<S> <C>
Deferred financing costs................................... $ 18,400
Environmental permits...................................... 1,418
PMI long term crude oil supply agreement................... 757
--------
$ 20,575
========
</TABLE>
The Company incurred deferred financing costs of $18.9 million associated
with the issuance of the $255.0 million in notes and having entered into the
$325.0 million secured construction and term loan facility. Amortization of
deferred financing costs for the period May 4, 1999 (inception) to December 31,
1999 was $0.5 million and is included in "Interest and finance cost, net".
The PMI long term crude supply agreement and environmental permits were
purchased from Clark Refining & Marketing. When the Coker Project is
operational, the Company will amortize the costs over the life of the
agreements.
7. Long-Term Debt
<TABLE>
<CAPTION>
December 31,
1999
--------------
(in thousands)
<S> <C>
Secured Construction and Term Loan Facility................ $ 105,000
12 1/2% Senior Secured Notes due January 15, 2009
(12 1/2% Senior Notes)..................................... 255,000
---------
$ 360,000
=========
</TABLE>
The 12% Senior Notes were issued by Port Arthur Finance in August 1999 on
behalf of the Company at par and are secured by substantially all of the assets
of the Company. The Company is required to pay a portion of the principal of
the notes on a set schedule on each January 15 and July 15, commencing July 15,
2002. The 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 75 basis points.
The Company has entered into a $325 million secured construction and term
loan facility to be provided by commercial banks and institutional lenders. The
construction and term loan is split into a Tranche A of $225 million with a
term of 7.5 years and a Tranche B of $100 million with a term of 8 years. Under
specified circumstances, the aggregate amount of the construction and term loan
facility may be reallocated between the tranches with the Company's consent,
which may not be unreasonably withheld. In addition, the Company has obtained a
$75 million secured working capital facility from commercial banks, which banks
include some of the same commercial banks that provide the construction and
term loan facility. In February 2000, our $75 million secured working capital
facility was reduced to $35 million. The $40 million reduction, a portion of
which had been outstanding in the form of a letter of credit to PMI to secure
against a default by us under our long-term oil supply agreement, was replaced
by an insurance policy under which an affiliate of American International Group
agreed to insure PMI against our default under the long term oil supply
agreement up to a maximum liability of $40 million. This affiliate of American
International Group is treated as a bank senior lender under the common
security agreement.
The 12 1/2% Senior Notes indenture and construction and term loan facility
credit agreement contains certain restrictive covenants including limitations
on distributions to our owners from our distribution account,
F-21
<PAGE>
limitations on Blackstone disposing of any equity interest in Clark Refining
Holdings, limitations on Clark Refining Holdings disposing of any equity
interest in Clark Refining & Marketing, the Port Arthur Refinery or the Company
and limitation on incurring additional senior debt. The Company was required to
provide a debt service reserve arrangement which was provided through an
insurance product that will be replaced with a cash funded reserve account from
available cash flow from operations.
Interest payments are due semiannually on Janaury 15, and July 15, for both
the 12 % Senior Notes and the Secured Construction and Term Loan Facility.
The scheduled maturities of long-term debt during the next five years are (in
millions): 1999, 2000 and 2001--$0; 2002--$5.3; 2003--$15.8; 2004 and
thereafter--$338.9.
8. Capital Contribution Receivable
In August 1999, Blackstone and Occidental signed capital contribution
agreements totaling $135 million. Blackstone agreed to contribute $121.5
million, and Occidental agreed to contribute $13.5 million to the Company. As
of December 31, 1999, Blackstone and Occidental contributed approximately $51.4
million and $5.7 million, respectively, of their commitments. The remaining
$77.8 million is recorded as a contribution receivable. The contractual
arrangements with Blackstone and Occidental provide that the aggregate $135
million equity commitment will be funded pro rata with the funding of the notes
and bank term debt, so that at the time of each advance of debt and equity to
pay construction costs the amount funded will be approximately 65% debt and 35%
equity. It is expected that the entire $135 million equity commitment will be
funded by March 2001. The obligations of Blackstone and Occidental to fund
their equity commitments are absolute, irrevocable and unconditional so long as
a pro rata portion of bank term debt is funded at the same time. The obligation
of Blackstone to fund its outstanding equity commitment may be assumed by a
third party if Blackstone transfers its equity interest in Clark Refining
Holdings to such third party and either (i) such third party is rated
investment grade by both S&P and Moody's after giving effect to such transfer
or (ii) a majority of lenders under the Secured Construction and Term Loan
Facility have consented to such transfer and either a majority of holders of 12
1/2% Senior Notes have consented or the Company has received a ratings
reaffirmation from both rating agencies with respect to the 12 1/2% Senior
Notes.
9. Interest and Finance Costs, Net
Interest and Finance Costs, Net were as follows:
<TABLE>
<CAPTION>
For the period
May 4 (inception)
to
December 31, 1999
-----------------
(dollars in
thousands)
<S> <C>
Interest expense........................................ $ 15,565
Finance expense......................................... 10,658
Capitalized interest.................................... (13,798)
Interest income......................................... (1,670)
--------
Interest and Finance Costs, Net......................... $ 10,755
========
</TABLE>
Finance expense included costs related to the Company's working capital
facility as well as insurance costs for working capital, a debt service reserve
arrangement and the PMI crude oil supply arrangement.
10. Commitments and Contingencies
In July 1999, the Company entered into a contract for the engineering,
procurement and construction of the Company's Coker Project with Foster Wheeler
USA. Under this construction contract, Foster Wheeler USA will continue to
engineer, design, procure equipment for, construct, test and oversee startup of
the Coker Project and integrate the Coker Project with the Port Arthur refinery
of Clark Refining & Marketing, Inc. Under
F-22
<PAGE>
the construction contract, the Company will pay Foster Wheeler USA a fixed
price of approximately $544 million of which $157.1 million was credited to the
Company for amounts Clark Refining & Marketing had already paid Foster Wheeler
USA for work performed on the Coker Project prior to August 1999. The Company
purchased this work in progress from Clark Refining & Marketing when the
financings were consummated in August 1999. The Company and Foster Wheeler USA
have the ability to initiate changes to work under the contract that may effect
the final total price paid. Changes in excess of $0.5 million individually or
$5.0 million in the aggregate must be approved by the project's independent
engineer. The contract has provisions whereby Foster Wheeler will pay the
Company up to $145 million in damages for delays in achieving mechanical
completion or guaranteed reliability, based on a defined formula. The Company
is required to pay Foster Wheeler USA an early completion bonus of up to $6
million if mechanical completion is achieved prior to November 1, 2000. The
Company can terminate the contract with Foster Wheeler USA at any time upon
written notice, at which time it will be obligated to pay actual project costs
to the date of termination, other costs related to demobilizing, canceling
subcontractors or withdrawing from the project site. Foster Wheeler USA cannot
terminate the contract unless the Company defaults on required payments under
the contract.
In August 1999, the Company entered into agreements with Clark Refining &
Marketing pursuant to which the Company will receive certain operating,
maintenance, and other services from Clark Refining & Marketing and will sell,
at market prices, the output from the new coking and hydrocracking equipment to
Clark Refining & Marketing for further processing into finished products. The
Company also entered into agreements under which it will process certain
hydrocarbon streams owned by Clark Refining & Marketing. In addition, the
Company entered into lease agreements under which it will lease Clark Refining
& Marketing's crude unit, vacuum tower, two distillate hydrotreaters, and a
naphtha hydrotreater at the Port Arthur refinery as well as the site where the
Company's new processing units are located. The Company will receive and pay
compensation at what it believes to approximate fair market value under these
agreements. At December 31, 1999, the Company had a net outstanding payable
balance of $0.4 million to Clark Refining & Marketing consisting of a payable
of $0.5 million for services under these agreements and fees paid by Clark
Refining & Marketing on the Company's behalf and a $0.1 million receivable for
the overpayment of such services in a prior period.
In August 1999, the Company purchased a long-term crude oil supply agreement
with PMI from Clark Refining & Marketing for approximately $0.8 million. The
contract includes a gross margin support mechanism designed to provide a
minimum average coker gross margin over its initial term. Pursuant to the terms
of the contract, PMI will supply to the Company Maya crude oil for a price
based on published market prices for crude and refined products, as defined in
the contract. The contract extends for eight years from the later of the start-
up date of the coker, the schedule completion date of January 2001 or the
guarantee date of July 2001. The completion date is the date the coker meets
prescribed operating performance. If the completion date extends beyond January
2001, the Company must pay P.M.I $400,000 per month for the first six months of
delay and $200,000 per month for up to an additional six months of delay
thereafter to extend the completion date or they may terminate the contract.
The Company may terminate the contract after paying PMI a termination payment
of approximately $170,000 per month after August 31, 1998 plus actual damages
that PMI has suffered. The Company does not currently anticipate the Coker
Project completion date being extended beyond January 2001.
In August 1999, the Company entered into an agreement with Air Products and
Chemicals, Inc. ("Air Products") to supply the hydrogen needs of the Coker
Project. Air Products will also supply steam and electricity to the Company
under this agreement. Prices under the contract are based on market prices at
the time of the contract, subject to adjustment according to a formula based on
inflation indices. Air Products will be required to pay the Company liquidated
damages of up to $1.2 million if the plant fails to be ready for commercial
operation on or before December 2000 and the Company will be required to pay
Air Products liquidated damages of up to $1.2 million if the Company is unable
to start-up the coker for initial operations prior to December 2000. The
Company does not currently anticipate the Coker Project initial start-up date
being extended beyond December 2000.
F-23
<PAGE>
Environmental laws typically provide that the owner 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. The Port Arthur
refinery is located on a contaminated site. Under the 1994 purchase agreement
between Clark Refining & Marketing and Chevron Products USA relating to the
Port Arthur refinery, Chevron retained environmental remediation obligations
regarding pre-closing contamination at over 97% of the refinery site. Clark
Refining & Marketing assumed responsibility for any remediation that is
required in and under the remaining 3% of the refinery site, which consists of
specified areas that extend 25 to 100 feet from active operating units,
including soil and groundwater. Clark Refining & Marketing has estimated its
liability for remediation of soil and groundwater soil in these areas at $27
million. Chevron is obligated to remediate the contamination is the areas for
which it has retained responsibility as and when required by law, in accordance
with remediation plans negotiated by Chevron and the applicable federal and
state agencies.
No part of our Coker Project site is located within the portion of the Port
Arthur refinery site for which Chevron retains environmental remediation
obligations. We have estimated remedial costs relating to our Coker Project
site, which surpasses 50 acres of the total Port Arthur refinery site surface
area, at $1.6 million. Clark Refining & Marketing has agreed to retain
liability regarding contamination existing at the Coker Project site and has
indemnified the Company against such liabilities; therefore, no such liability
has been recorded at the Company. However, if Clark Refining & Marketing does
not fulfill its remediation obligations, the Company could incur substantial
additional costs in remediating the contamination.
F-24
<PAGE>
ANNEX A
ADDITIONAL INFORMATION REGARDING CLARK REFINING & MARKETING
[Annex A to be updated by amendment to this registration statement with
corresponding disclosure from Clark Refining & Marketing's 1999 Annual Report
on Form 10-K]
A-1
<PAGE>
ANNEX B
- --------------------------------------------------------------------------------
INDEPENDENT ENGINEER'S REPORT ON
PORT ARTHUR COKER COMPANY PROJECT
- --------------------------------------------------------------------------------
Prepared by:
[Logo of Purvin & Gertz, Inc.]
Dallas -- Houston -- Los Angeles
London -- Calgary
Buenos Aires -- Singapore
August 10, 1999 Ken E. Noack
Anthony E. Chodorowski
Stephen N. Fekete
<PAGE>
TABLE OF CONTENTS
<TABLE>
<S> <C>
I.INTRODUCTION........................................................... B-1
PROJECT OVERVIEW...................................................... B-1
SCOPE OF REVIEW....................................................... B-2
II.PROJECT PARTICIPANTS................................................... B-4
CLARK REFINING HOLDINGS INC........................................... B-4
FOSTER WHEELER USA CORPORATION........................................ B-5
AIR PRODUCTS AND CHEMICALS INC........................................ B-5
PETROLEOS MEXICANOS/P.M.I. COMERCIO INTERNACIONAL..................... B-5
III.CONCLUSIONS........................................................... B-7
TECHNICAL............................................................. B-7
COMMERCIAL AND MARKETING.............................................. B-8
FINANCIAL PROJECTIONS................................................. B-10
STAND-ALONE CASE...................................................... B-10
IV.DISCUSSION OF FINDINGS................................................. B-12
PROCESS DESCRIPTION................................................... B-12
UPGRADE PROJECT COSTS................................................. B-14
UPGRADE PROJECT SCHEDULE.............................................. B-17
TECHNOLOGY ASSESSMENT................................................. B-17
DELAYED COKER....................................................... B-17
VGO HYDROCRACKER.................................................... B-17
SULFUR RECOVERY..................................................... B-17
REFINERY RENOVATIONS AND UPGRADES................................... B-18
OFFSITES, AND UTILITIES............................................. B-18
PROJECT CONTRACTS..................................................... B-19
CRUDE OIL SUPPLY AGREEMENT.......................................... B-19
PRICING FORECAST AND EFFECT ON PMI CONTRACT....................... B-20
APCI HYDROGEN CONTRACT.............................................. B-21
REVIEW OF INTERCOMPANY AGREEMENTS................................... B-21
COKER COMPLEX GROUND LEASE AND BLANKET EASEMENT AGREEMENT ("GROUND
LEASE").......................................................... B-22
ANCILLARY EQUIPMENT SITE LEASE AND EASEMENT AGREEMENT ("ANCILLARY
EQUIPMENT LEASE")................................................ B-22
PRODUCT PURCHASE AGREEMENT........................................ B-23
SERVICES AND SUPPLY AGREEMENT..................................... B-23
ENGINEERING, PROCUREMENT, AND CONSTRUCTION CONTRACTS................ B-24
CLARK EPC CONTRACT................................................ B-24
EPC CONTRACT...................................................... B-24
CONTRACTOR RESPONSIBILITIES...................................... B-24
PROJECT COST AND SCHEDULE........................................ B-25
CHANGES IN LAWS OR REGULATIONS................................... B-25
FORCE MAJEURE AND OWNER DELAYS................................... B-25
CHANGE ORDERS.................................................... B-25
WARRANTIES....................................................... B-26
PERFORMANCE TESTS AND COMPLETION GUARANTEE....................... B-26
INDEPENDENT ENGINEER............................................. B-27
CONSTRUCTION MONITORING.......................................... B-27
</TABLE>
i
<PAGE>
<TABLE>
<S> <C>
CAPACITY TEST........................................................ B-28
CAPACITY TEST PARAMETERS............................................. B-28
RELIABILITY TEST..................................................... B-29
ENVIRONMENTAL REVIEW................................................... B-32
ENVIRONMENTAL PERMITS AND COMPLIANCE................................. B-32
FLEXIBLE AIR PERMIT ALTERATION AND SEPARATION........................ B-32
WASTEWATER AND, SOLID AND HAZARDOUS WASTES........................... B-33
EXISTING SITE CONTAMINATION.......................................... B-33
EFFECT OF PROPOSED GASOLINE SULFUR SPECIFICATIONS.................... B-34
MTBE................................................................. B-34
COMPETITIVENESS OF REFINERY............................................ B-35
V.ECONOMIC MODEL........................................................... B-36
GENERAL................................................................ B-36
CAPITALIZATION OF THE PACC............................................. B-36
REVENUES............................................................... B-37
FEEDSTOCKS TO PACC..................................................... B-38
YIELDS FROM PACC....................................................... B-38
OPERATING COSTS AND SUSTAINING CAPITAL................................. B-38
PROCESSING/LEASE FEES................................................ B-41
AMORTIZATION......................................................... B-42
CONSTRUCTION MANAGEMENT SERVICES..................................... B-42
DEBT SERVICE COVERAGE RATIOS........................................... B-43
BASE CASE............................................................ B-44
SENSITIVITIES........................................................ B-44
BASE CASE--NO PMI CONTRACT......................................... B-44
BACKCAST CASE...................................................... B-44
BACKCAST CASE--NO PMI CONTRACT..................................... B-44
DOWNSIDE CASE...................................................... B-44
REDUCED UTILIZATION CASE........................................... B-45
REDUCED COKER YIELD AND REDUCED HYDROCRACKER
CONVERSION CASES.................................................. B-45
OPERATING COST INCREASE CASE....................................... B-45
STAND-ALONE CASE....................................................... B-45
CONFIGURATION........................................................ B-45
PRODUCTS............................................................. B-46
PRICING.............................................................. B-46
OPERATING COSTS...................................................... B-47
DSCR................................................................. B-47
APPENDIX A................................................................. B-68
</TABLE>
ii
<PAGE>
INDEPENDENT ENGINEER'S REPORT
I. INTRODUCTION
Purvin & Gertz, Inc. ("PGI") has been retained as Independent Engineer ("IE")
to review certain aspects of the Port Arthur Coker Company L.P. heavy oil
upgrade project as defined herein. The heavy oil upgrade project is to be
constructed at the Clark Refining & Marketing, Inc. ("Clark") refinery located
at Port Arthur, Texas.
This report has been prepared by PGI on behalf of financing parties and
lenders of senior debt (collectively, the "Financing Parties") to a newly
formed limited partnership, the Port Arthur Coker Company L.P. ("PACC") and its
wholly owned subsidiary, Port Arthur Finance Corp. PGI understands that this
report will be provided to certain insurance companies and included as an
appendix to preliminary and final offering circulars, bank syndicate
information memoranda and prospectuses relating to the offer and sale of senior
debt securities of the PACC and its affiliates. PGI consents to this report
being so included as an appendix to such preliminary and final offering
circulars, bank syndicate information memoranda and prospectuses, subject to
the limitations expressed therein. Certain information contained in this report
is covered under confidentiality agreements between Clark and third parties.
PGI conducted this analysis and prepared this report utilizing reasonable
care and skill in applying methods of analysis consistent with normal industry
practice. All results are based on information available at the time of review.
Changes in factors upon which the review is based could affect the results.
Forecasts are inherently uncertain because of events or combinations of events
that cannot reasonably be foreseen including the actions of government,
individuals, third parties and competitors. NO IMPLIED WARRANTY OF
MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE SHALL APPLY.
PGI has not addressed potential year 2000 recognition problems in this
analysis and the results assume zero impact from year 2000 recognition
problems.
Some of the information on which this report is based has been provided by
the Upgrade Project participants, including Clark. PGI has utilized such
information without verification unless specifically noted. PGI accepts no
liability for errors or inaccuracies in information provided by others.
All defined terms are either defined in this document, in the Definitions to
the Intercompany Agreements (as defined herein), or in the EPC Contract (as
defined herein).
PROJECT OVERVIEW
An 80,000 barrel per stream day ("bpsd") delayed coker, a 35,000 bpsd vacuum
gas oil ("VGO") hydrocracker, a 417 long tons per day ("LTD") sulfur recovery
unit ("SRU"), revamps to the existing crude unit, vacuum unit, hydrotreaters
and certain offsites (the "Upgrade Project") will be constructed at Clark's
Port Arthur, Texas refinery (the "Refinery") in order to add additional heavy
sour crude oil, primarily Mexican Maya, processing capabilities. PACC will be
established in order to construct, own and operate the coker, hydrocracker, SRU
and certain offsites. PACC will also lease 100% of Clark's existing crude unit,
vacuum unit, and three hydrotreaters (naphtha, jet and diesel), and will have
access to all necessary Clark-owned common facilities under the Ancillary
Equipment Site Lease And Easement Agreement and the Coker Complex Ground Lease
And Blanket Easement Agreement (all described herein). (See Figure I-1 for
listing of major facilities included in the scope of the Upgrade Project).
Clark will also provide other services and utilities to PACC under the Services
and Supply Agreement (as described herein) and will purchase all products
produced by PACC under the Product Purchase Agreement (described herein). The
Ancillary Equipment Site Lease And Easement Agreement, the Coker Complex Ground
Lease And Blanket Easement Agreement, the Services and Supply Agreement and the
Product Purchase Agreement will be referred to as a group throughout this
report as "Intercompany Agreements". PACC will also be the assignee of the
crude oil supply agreement ("PMI Contract"--see description herein) which
provides for a minimum supply of Maya crude oil and contains a mechanism for
stabilizing coker gross margin. PACC will enter into a fixed price turn-key
("LSTK") engineering, procurement and construction contract (the "EPC
Contract") with Foster Wheeler USA
B-1
<PAGE>
Corporation ("Foster Wheeler") in order to construct the new units ("PACC
Project"). Clark will enter into a separate "cost-plus" reimbursable contract
with Foster Wheeler (the "Clark EPC Contract") for the renovation and upgrade
of certain existing Refinery units and offsites required for the PACC Project
("Clark Project"). Air Products and Chemicals, Inc. ("APCI") will design,
construct and operate a hydrogen plant on the Refinery site to supply PACC's
hydrogen requirements secured by a long term contract between PACC and APCI
("Hydrogen Contract"). Clark will also contract for steam and electricity to be
produced at the APCI hydrogen plant.
[Chart of Figure I-1
Major Facilities Included in Upgrade Project]
SCOPE OF REVIEW
PGI has reviewed certain technical, environmental and economic aspects of the
Upgrade Project as listed below:
. Upgrade Project design basis
. PACC Project integration with Clark Project
. PACC Project and Clark Project cost estimates and construction schedules
. Construction and procurement strategy
. Handling, storage and disposal of coke
. Principal Upgrade Project participant capabilities
. PACC Project charge, yield and operating cost projections
. Intercompany Agreements
B-2
<PAGE>
. Environmental permits and safety data
. PACC Project Base Case economic model, sensitivities and stand-alone case
. Project contracts and documentation as listed in Appendix A
. Hydrogen supply
PGI also conducted interviews with key members of the Upgrade Project
management team. PGI has also prepared a separate Crude Oil and Refined Product
Market Forecast which provides the basis for the crude oil and product prices
utilized in PACC economic projections and which confirms that sufficient Maya
crude oil will be available to fulfill the supply obligations under the PMI
Contract.
PGI conducted this analysis and prepared this report utilizing reasonable
care and skill in applying methods of analysis consistent with normal industry
practice. In the preparation of this report and the opinions expressed, PGI has
made certain assumptions with respect to conditions which may exist or events
which may occur in the future. All results and conclusions are based on
information available at the time of the review. Changes in factors upon which
the review is based could affect the results and the conclusions.
The principal assumptions and considerations made by PGI in developing the
results and conclusions presented in this report include the following:
. As IE, PGI has made no determination as to the validity and
enforceability of any contract or agreement applicable to the Upgrade
Project. However, for purposes of this report, PGI has assumed that all
such contracts and agreements will be fully enforceable in accordance
with their respective terms and that all parties will comply with the
provisions of such contracts and agreements. In addition, PGI has assumed
that the Upgrade Project has or will comply with all regulations that may
be applicable thereto.
. As IE, PGI has reviewed the design practices and cost estimating methods
employed for the Upgrade Project to determine if industry standards and
practices were followed; however, PGI has not re-performed design or cost
estimate calculations. PGI's review has been conducted utilizing
reasonable care and skill in accordance with customary industry standards
and provides a reasonable basis for the conclusions contained in this
report.
. Foster Wheeler, as the Upgrade Project contractor and Clark, as operator,
will construct, manage operation of and maintain the Upgrade Project in
accordance with good industry standards and practices.
. Clark and PACC will make all required renewals and replacements in a
timely manner, and will not operate equipment to cause it to exceed the
equipment manufacturer's recommended maximum ratings for extended periods
of time.
B-3
<PAGE>
II. PROJECT PARTICIPANTS
[Chart of Figure II-1 Project Participants]
CLARK REFINING HOLDINGS INC.
Clark Refining Holdings Inc. ("Clark Holdings") is principally owned by
Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates
("Blackstone") and Occidental Petroleum Corporation ("Oxy"). The company's
operations include refining, marketing, and supply and transportation of
petroleum products.
Clark Holdings, through its 100% wholly owned operating subsidiary Clark
Refining & Marketing, Inc. owns and operates three Midwest oil refineries and
the Port Arthur oil refinery. The Midwest refineries are located in Lima, Ohio
(capacity 170,000 bpsd), Blue Island, Illinois (capacity 80,000 bpsd), and
Hartford, Illinois (capacity 65,000 bpsd). The Gulf Coast refinery is located
in Port Arthur, Texas (capacity 232,000 bpsd). The company is currently the
fifth largest independent refiner in the U.S. and markets gasoline, diesel fuel
and other petroleum products on a wholesale unbranded basis. On July 8, 1999,
Clark Holdings announced that it had disposed of its retail marketing assets
for cash proceeds of $230 million.
Clark Holdings is experienced in undertaking capital projects. In 1998, the
company had capital expenditures of approximately $160 million. The company has
executed two large scale refinery acquisition projects in the last four years
totaling over $440 million. In addition, the company has extensive experience
in
B-4
<PAGE>
operating coker units. The Lima, Hartford and Port Arthur refineries all have
operating coker units with a combined capacity of 70,000 bpsd.
FOSTER WHEELER USA CORPORATION
Foster Wheeler designs, engineers and constructs petroleum, chemical,
petrochemical and alternative-fuels facilities. In addition, Foster Wheeler
owns and licenses patents, trademarks and proprietary knowledge which are used
in each of its industry groups. Foster Wheeler Corporation, the parent of
Foster Wheeler, had revenues totaling $4,597 million and total assets of $3,495
million for the year ending December 31, 1998, and has approximately 11,000
employees.
Foster Wheeler has designed and built over 100 cokers, representing 80% of
the existing cokers in the world. These include many comparable projects that
are in various phases of completion such as:
.Shell--Martinez, Norco, Deer Park, Moerdijk, and Buenos Aires refineries
.PEMEX--Madero, Minatitlan, Salina Cruz, and Cadereyta refineries
.Koch--Corpus Christi refinery
.Chevron--Salt Lake City, and Pascagoula refineries
.Exxon/Mobil--Baton Rouge, and Paulsboro refineries
In addition to the construction of coker units, Foster Wheeler also has
extensive experience in building hydrocracking units. Since the 1960s, the
company has executed over 30 hydrocracker projects. During the last ten years,
the company has performed 39 engineering, procurement and construction
projects, and currently has 3 Orinoco Belt extra-heavy oil upgrade projects in
engineering stages. PGI views Foster Wheeler as the industry leader in the
design and construction of coker units, and believes the company is the well
qualified choice for the execution of the Upgrade Project.
AIR PRODUCTS AND CHEMICALS INC.
APCI is a multinational corporation which produces industrial gases,
chemicals and energy/environmental systems. The company has developed expertise
in supplying industrial gases for over 50 years. APCI operates and maintains
over 300 air separation facilities worldwide. As well as being an operating
company, APCI is an experienced designer and builder of cryogenic plants and
equipment for gas and liquid production, recovery, purification and
liquefaction. For the year ending December 31, 1998, APCI had revenues totaling
$4,919 million and total assets of $7,490 million.
APCI is very experienced in the construction and operation of hydrogen
production facilities with 32 steam methane reformers and 14 offgas
recovery/purification plants in operation around the world. Since 1992, APCI
has been allied with Kinetics Technology International ("KTI") a leading
supplier of hydrogen plants to the refinery industry. The APCI/KTI alliance has
constructed and continues to operate several onsite hydrogen plants for
refineries similar to the facility proposed for Clark. PGI believes that APCI
is well qualified to construct and operate the proposed hydrogen plant which
will be capable of supplying the Upgrade Project with its hydrogen requirements
and, in addition, electricity and steam.
PETROLEOS MEXICANOS/P.M.I. COMERCIO INTERNACIONAL
Petroleos Mexicanos ("Pemex") is the national oil company of Mexico and one
of the world's largest producers of crude oil and natural gas with 1997
revenues in excess of $30 billion. Pemex is the sole developer of Mexico's
crude oil and natural gas reserves, which in the aggregate rank in the top ten
accumulations of known hydrocarbons in the world and have an estimated current
reserve life of approximately 40 years. Pemex is also a major manufacturer and
distributor of refined petroleum products and basic petrochemical feedstocks.
The company owns and operates six domestic refineries and owns a 50% interest
in the Shell Deer Park
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Refining Company in Texas. As a wholly owned entity of the Mexican state, Pemex
is a major contributor to the country's federal budget. In 1997, Pemex's
federal taxes and duties represented 36.6% of the total federal budget. P.M.I.
Comercio Internacional, S.A. de C.V. ("PMI") which is 93% owned by Pemex and 7%
owned by branches of the Federal Government of Mexico, is the international
trading arm of Pemex responsible for all exports.
Pemex produces three primary types of crude oil for export: (i) Isthmus, a
light crude oil, 33.6(degrees) API density and 1.3 weight % sulfur, (ii) Maya,
heavy crude oil, 22(degrees) API density and 3.3 weight % sulfur, and
(iii) Olmeca, a very light crude oil, 39.3(degrees) API density and 0.8 weight
% sulfur. The U.S. is the dominant export market for Pemex with 80% of total
exports in 1998. Maya crude oil exports totaled 1 million barrels per day in
1998 and are expected to increase throughout the forecast period. Pemex through
PMI has been actively seeking to expand the otherwise limited market for its
increasing reserves of Maya crude oil by offering attractive long term crude
oil supply agreements. The U.S. has been the targeted market for these
agreements since Pemex realizes the highest value for its crude oil in the U.S.
market due to lower transportation costs. PMI has signed long term supply
agreements with Clark, Coastal Corp., Deer Park Refining L.P., Marathon Ashland
Petroleum and Exxon Corp., of which Clark's is one of the largest.
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III. CONCLUSIONS
In PGI's opinion, the Upgrade Project will transform the Refinery into one of
the top five refineries on the Gulf Coast in terms of competitiveness and heavy
crude oil conversion capacity. The investment in the Upgrade Project is
consistent with Clark Holdings overall strategy and will allow Clark to further
improve its market position in a very competitive environment. Based on our
review of the Upgrade Project, PGI has reached the following technical,
commercial/marketing and financial conclusions:
TECHNICAL
1. The design of the major new units to be installed at the Refinery,
specifically the delayed coker and the hydrocracker process units, are
based on licensed technology that is well established and commercially
proven. Clark has obtained and will transfer to PACC a process license
from Chevron Research and Technology Company ("Chevron"), a subsidiary
of Chevron USA, for the hydrocracking technology and will obtain the
Foster Wheeler delayed coking technology as part of the EPC Contract.
The size and configuration of the new process units should integrate
well with the Refinery.
2. The Upgrade Project capital cost estimate provided by Foster Wheeler
and Clark of $636 million for the construction of new units, offsites,
and revamps is reasonable and includes all relevant items based on
PGI's review of the estimate. The contingency and escalation allowance
included in the estimate is adequate at this stage of the Upgrade
Project. The total Upgrade Project cost including owner's costs,
additional contingency, financing costs and interest during
construction is $833 million.
3. The Upgrade Project schedule of 31 months from April 1998 to mechanical
completion at November 1, 2000 is achievable. Field construction work
in the areas of site preparation, piling, foundations, and structural
are currently underway. As of June 1999, 98% of the major equipment has
been placed on order and 70% of the final design and engineering work
has been completed, and civil construction is very advanced.
4. Clark obtained an umbrella flexible air emissions permit which was
amended as of August 31, 1998 to allow construction and operation of
the Upgrade Project. In May 1999, the PACC units were removed from
Clark's flexible permit and a new permit for such units was issued to
PACC. PACC will have all permits required to construct, own and operate
the PACC Project, including the stand-alone case, as needed. PACC also
obtained a standby permit in July 1999 to allow PACC to have its own
permit to cover the entire Refinery, including the Ancillary Equipment,
if it is needed in the event of a Clark bankruptcy or otherwise. The
wastewater treatment facility is a state of the art design and will be
able to accommodate the effluent from the Upgrade Project in compliance
with environmental regulations and requirements. Solid and hazardous
wastes are reported to be handled, stored and transported according to
the required regulations and do not present any non-compliance issues.
5. There are no apparent site conditions including known underground
obstructions or contamination that would lead to major cost overruns.
All of the major site excavation has been completed.
6. The Upgrade Project will have a useful life of at least twenty years
extending well beyond the term of the debt financing.
7. Foster Wheeler is a reputable engineering contractor experienced in
designing and constructing refining and petrochemical facilities. In
addition, PGI believes that Foster Wheeler is well qualified for the
proposed assignment and has the resources and financial strength
necessary to fulfill their obligations under the EPC Contract and Clark
EPC Contract.
8. The EPC Contract specifies a fixed price ($544 million) and a firm
mechanical completion date. The EPC Contract terms and conditions are
very specific in protecting price, efficiencies and completion
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date, and incorporate substantial penalties in the event of schedule
delays. In addition, Foster Wheeler has indicated that the EPC Contract
contains a contingency amount of $35 million. In PGI's opinion the EPC
Contract is favorable to PACC, suitable for this type of financing, and
provides adequate protection to PACC for cost overruns, completion risk,
integration risk and inefficiencies.
9. No owners of PACC or Clark will provide a completion guarantee for the
Upgrade Project. Foster Wheeler will be responsible for satisfying the
required performance and reliability tests including meeting the
contractual capacity and efficiency process guarantees. Tests have been
structured to validate the cash flow availability in order to support
the anticipated debt service capacity and if not, to cause Foster
Wheeler to buy down the debt to adjust it according to the reduced debt
capacity. The liquidated damages cap of $145 million represents up to
$70 million of delay damages and up to $75 million of buydown damages
for inefficiencies and is adequate for this type of project. PGI will
monitor the construction progress and funds disbursements for the EPC
Contract and witness and approve the performance/reliability tests.
10. The crude unit and hydrotreater modifications, and other offsites and
utilities will be undertaken by Foster Wheeler under the Clark EPC
Contract. These types of modifications are a group of relatively
routine small refinery projects normally carried out during turnarounds
or during refinery operation that Clark and PGI expect to cost $92
million. The major components of Clark's responsibility, the crude unit
revamp and interconnecting piping, are planned to be complete and in
operation at least six months prior to the EPC Contract Target
Mechanical Completion Date. PGI believes that the Clark Project will
not present a major risk to the successful startup, operation and
integration of the PACC Project.
11. Clark is an experienced fuels refinery operator currently processing
Maya crude oil and operating two existing cokers at the Refinery. PGI
believes that Clark is well qualified to manage operations at the
Refinery.
12. The newly constructed units can be reasonably expected to achieve the
on-stream factors in the Base Case projections. The Base Case
projections include a reduced on-stream factor through 2000 to reflect
startup and achieving a steady operation.
13. The crude import infrastructure at Clark's facilities and at Sun Pipe
Line Company's ("Sun") Nederland terminal and connecting pipelines to
the Refinery facilities are adequate to support the volumes of imported
Maya and other crude oils contemplated for the Upgrade Project's
operation. Several pipeline and terminal alternatives also exist to
deliver crude oil to the Refinery if required.
14. A new hydrogen plant will be constructed at the Refinery by APCI in
support of both PACC and Clark's hydrogen requirements. The capacity of
the hydrogen plant will be in excess of the Upgrade Project's
requirements and an amount equivalent to approximately 69% of the total
Hydrogen Contract volume will be sold under contract to PACC on a "take
and pay, if delivered" basis. Clark will also contract for steam and
electricity to be produced at the APCI plant. PGI believes that APCI is
a reliable hydrogen producer and that the plant will be constructed in
a timely manner and that it will produce the required hydrogen and
utilities at the contract specifications. Approximately 50% of the
required hydrogen can be supplied by APCI via pipeline as a backup, if
necessary.
COMMERCIAL AND MARKETING
1. Clark has entered into the PMI Contract with PMI that will be assigned
to PACC simultaneously with the close of the PACC financing. The PMI
Contract was designed to minimize the effect of adverse refining
cycles, thereby establishing more stable cash flow for PACC. In order
to effect stable cash flows, the PMI Contract contains a formula that
is intended to be an approximation for coker gross margin and is
designed to provide for a minimum average coker gross margin for the
first eight years
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following completion of the Upgrade Project. The mechanism, which is
more fully described in the Project Contracts section, guarantees an
average minimum $15.00 per barrel Differential formula related to coker
gross margin via price adjustments on Maya crude oil. If the
Differential formula amount is calculated over the August 1987 to
December 1998 period and regressed against the historical WTI/Maya
differential, the mathematical results implies that the $15/bbl is
equivalent to the WTI/Maya differential of $5.94/bbl. This is $0.24/bbl
above the historical average WTI/Maya differential of $5.70/bbl over the
same period. PGI has reviewed the PMI Contract and believes the
mechanism serves as a suitable method of stabilizing coker gross margin
fluctuations.
2. Clark will offtake all the intermediate and final products produced by
PACC and will provide services to PACC on a routine contractual basis.
Clark will be able to incorporate the products from PACC into the
Refinery and has considerable experience in selling finished products
into the Gulf Coast market. The volume of incremental finished products
produced by the Refinery as a result of the operation of the Upgrade
Project (a 15% increase) will be minor in proportion to the entire Gulf
Coast market (about 1/2% of current market) and its growth forecast and
PGI does not expect such volume to impact the market. The product
offtake, operation, maintenance and other services are provided under
Intercompany Agreements between Clark and PACC (see Project Contracts
for description). In PGI's opinion, the Intercompany Agreements will
transact products and services that are priced to reflect arms-length
mechanisms and market-based prices and contain fair market terms.
3. Based on PGI's analysis of the worldwide heavy oil supply and demand
fundamentals and plans and objectives stated by Pemex and PDVSA, PGI
forecasts that heavy crude production will continue to increase through
the term of the PACC financing. The crude oil heavy/light differential
(defined as WTI Cushing minus Maya FOB Mexico) is forecast to average
$6.00 per barrel or above in constant 1999 dollars over the same
period. This is equivalent to a $15.16 per barrel coker gross margin as
defined by the Differential formula in the PMI Contract. This forecast
is consistent with the expectation that coker projects will continue to
develop in an orderly fashion in line with the expected heavy crude oil
production increases.
4. PGI believes that PEMEX/PMI have sufficient Maya crude oil reserves to
fulfill the supply obligation under the PMI Contract. PGI believes the
risk of diversion of Maya crude oil away from PACC is minimal because:
(i) Mexico is significantly increasing production of Maya; (ii) the
number of other sour crude refineries able to process Maya are very
limited; (iii) the demand for heavy crude oil outside the U.S. is small
and PGI does not expect demand to change during the forecast period;
and (iv) the netback for heavy crude oil shipments to Europe or Asia is
low relative to U.S. Gulf Coast deliveries.
5. While the Upgrade Project is designed to process Maya crude oil as its
primary feedstock, it will have the flexibility of processing other
similar quality heavy sour crude oils and will be able to achieve
essentially equivalent economics to the Base Case projections (the
"Base Case") with minimal changes to configuration excluding any
benefits of the coker gross margin guarantee in the PMI Contract.
6. The shutdown of the Refinery is, in the opinion of PGI, an extremely
remote possibility due to its competitiveness post-completion of the
Upgrade Project.
7. The terms of each of the Product Purchase Agreement, the Services and
Supply Agreement, the Ground Lease and Blanket Easement Agreement and
the Ancillary Equipment Site Lease and Easement Agreement are as
favorable to Clark and to PACC, in all material respects, as terms that
would be obtainable at this time for a comparable transaction or series
of similar transactions in arm's length dealings with a person who is
not an affiliate. In the opinion of PGI, payments to be made by Clark
to PACC under the Product Purchase Agreement and the Services and
Supply Agreement are fair consideration for the products acquired or
services received.
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8. The consideration PACC will pay Clark for PACC's assumption of the PMI
Contract, PACC's acquisition of work in progress under the construction
contract and Clark's reduction of the permissible emissions levels
under one of its air emissions permits in order to allow PACC to obtain
its air permit is equal to the fair market value of such assets. Clark
will receive rental payments under both the Ground Lease and Blanket
Easement Agreement and the Ancillary Equipment Site Lease and Easement
Agreement equal to the fair market value rental payments of the
property leased.
FINANCIAL PROJECTIONS
1. The Base Case assumes that the PACC-owned units are operated as part of
the Refinery. Assuming a PGI price forecast, the estimated average
operating cash flow over the initial 11 year operating period for PACC
is approximately $228 million per year and the after-tax cash flows
generated by PACC will be sufficient to repay PACC debt obligations
(scheduled principal amortization and interest) with minimum and
average debt service coverage ratios ("DSCR") of 2.0 and 2.4,
respectively.
2. PGI analyzed various sensitivity cases including a backcast (1989-
1998). PGI presents the back cast from 1989-1996 (the "Backcast Case")
because the PACC debt has a term of eight years after start-up. PGI
concludes that in all cases PACC can comfortably meet its debt service
obligations. The PMI Account provides liquidity during low coker margin
periods. This can be seen in the Backcast Case with minimum and average
DSCRs of almost 1.0 and 2.0 respectively. In 2007 (DSCR of almost 1.0)
where the debt service shortfall amounts to $3.0 million, the PMI
Account is fully funded with $50 million. In the Backcast Case without
the PMI Contract in place, cash flow shortfall amounts to $5.0 million,
with a debt service reserve account of $37 million and over $100
million of cash available for debt service. The PMI Account effectively
mitigates the timing issue of a delay in receiving discounts after
prior period surpluses. When fully funded and combined with the debt
service reserve account, these reserve accounts provide approximately
1.25 years of debt service coverage.
3. The proceeds of the total financing combined with the proposed equity
should be sufficient to pay the total estimated Upgrade Project cost of
$833 million.
4. If the PACC-owned units and the modifications to the Ancillary
Equipment are designed, constructed, operated and maintained as
currently proposed, PACC should be capable of meeting or exceeding the
production projections.
5. The basis for the estimate of PACC's total costs of operating and
maintaining the PACC facilities is in accordance with standard industry
practice. The operating and maintenance costs set forth in the Base
Case projections provide sufficient funds for the operations and
maintenance of the PACC facilities consistent with the operating
scenarios presented.
STAND-ALONE CASE
To demonstrate the robustness of the economics of PACC and to ensure that
PACC can be operated independently from Clark, PGI developed a stand-alone case
that assumes the following:
. PACC continues its operations while operations at the rest of the
Refinery are discontinued, other than the units PACC owns, is leasing or
has a right to use under the Coker Complex Ground Lease.
. PACC uses the full capacity of the leased and owned facilities.
. A third-party is managing the operation of all PACC leased and owned
units for PACC.
. PACC continues to purchase crude oil under the PMI Contract.
. A third party is marketing all intermediate and finished products on
behalf of PACC.
. PACC's rights to possession under the Ancillary Equipment Site Lease and
Coker Complex Ground Lease remain in effect.
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In this regard PGI believes that:
1. From a technical standpoint, PACC could successfully continue to
operate in a stand-alone mode given the preceding assumptions.
2. The modifications necessary to achieve stand-alone operation are
relatively minor and could be achieved within three months and will
cost less than $5 million.
3. The intermediate and finished products produced from a stand-alone
operation should be readily marketable based on appropriate discounts
for quality to spot market prices to long term off-takers since PACC is
located in the most liquid refinery products market in the world.
Discounts are applied to naphtha and VGO over a three-year period to
account for the market disruption caused by introducing a large volume
of intermediate products into the market.
4. Even in this extremely unlikely scenario, PACC is able to service its
debt obligations after paying all operating expenses as evidenced by
projected minimum and average after tax DSCRs of 1.1 and 1.9,
respectively.
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IV. DISCUSSION OF FINDINGS
PROCESS DESCRIPTION
The Refinery is currently configured to process a medium sour crude oil slate
as limited by delayed coker and hydrotreating capacity. The design basis of the
Upgrade Project is a refinery crude oil throughput of 250,000 bpsd of primarily
a heavy sour crude oil slate consisting of up to 210,000 bpsd of Maya and
40,000 bpsd of light opportunity crude which is assumed to be Arab Light in the
Base Case. PACC has been established to facilitate the construction of an
80,000 bpsd delayed coker, a 35,000 bpsd VGO hydrocracker, and a 417 LTD sulfur
recovery plant. In addition, modifications will be made to existing units
throughout the Refinery to enable processing of the heavy crude oil slate. The
units to be modified, which will remain under Clark ownership, include the
crude/vacuum unit, the distillate hydrotreaters, the naphtha hydrotreater, and
the crude oil feed system. Other offsites will also be constructed in support
of the Upgrade Project. The simplified block flow diagram in Figure IV-1 below
illustrates the interaction of the PACC units and the Clark units.
[BLOCK FLOW DIAGRAM]
(1) Third party designed, constructed, owned and operated.
(2) Includes sour water stripper and amino treated units.
(3) Owned by Clark R&M.
(4) Purchased by the PACC under the PMI Contract
(5) Purchased by Clark and not covered by the PMI Contract
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The delayed coker is designed to process 80,000 bpsd of vacuum resid and is
equipped with 6 coking drums. The delayed coking unit converts vacuum residue
via thermal cracking to lighter more valuable products, namely heavy gas oil
which is fed to the hydrocracker, light gas oil which is blended to the
distillate pool after further processing, naphtha feed for the reformer,
butane/butylene, propane/propylene, and fuel gas. The delayed coker being
constructed is a modern Foster Wheeler design incorporating a low operating
drum pressure and a low recycle rate. Coke from the unit is currently planned
to be loaded by crane into rail cars for sale by PACC to Clark.
The VGO hydrocracker is a 2-stage Chevron design with a design operating
pressure of 2500 psig. The unit is designed to process 35,000 bpsd of feedstock
consisting of coker heavy gas oil, virgin VGO, and light cycle oil from the
Clark fluid catalytic cracking unit ("FCCU"). The unit is designed for 50 vol%
conversion of the heavy feedstock. Full conversion of the VGO is not required
in the hydrocracker since the existing 77,000 bpsd FCCU has enough capacity to
convert the remainder of the unconverted VGO from the hydrocracker which will
be low sulfur quality. This allows the hydrocracker to have a smaller second
stage reactor than is typical for full conversion VGO hydrocrackers, which
reduces the capital cost of the hydrocracker.
The new sulfur recovery plant is rated at a sulfur capacity of 417 LTD. In
addition to the sulfur plant, a new Shell Claus Offgas Treater ("SCOT") tailgas
unit is being constructed as well as a sour water stripper and amine
regenerator. Recovered sulfur will be purchased by Clark and shipped via rail
at a new rail siding.
Modifications to the existing Refinery units include upgrading the
crude/vacuum unit from the existing 232,000 bpsd of crude oil feed to 250,000
bpsd of crude oil feed. The modifications include changes to process exchangers
to provide more preheat to the vacuum tower, upgrading the vacuum tower heater,
and miscellaneous pumps and piping. In addition, the GFU 243 distillate
hydrotreater has been modified by the replacement of the existing reactor which
will extend the cycle length and capability of the unit. These modifications
are scheduled to be completed at least six months prior to the mechanical
completion of the coker, hydrocracker and SRU (currently estimated at November
1, 2000). In addition to the GFU 243 hydrotreater reactor replacement, the GFU
241 hydrotreater (which is not being leased) reactor will be replaced with a
new reactor, and the GFU 242 hydrotreater existing two reactors are being
replaced with the reactor from GFU 243. These modifications are to ensure
adequate cycle life upon completion of the Upgrade Project.
A new naphtha hydrotreater guard bed reactor will be installed on the coker
plot site to remove silica and di-olefins from the coker naphtha. Silica is
used to control foaming in the coke drums and has a boiling point in the
naphtha range. Silica is a permanent poison for reformer catalyst and must be
removed prior to processing in the reformer. Di-olefins are unstable compounds
which tend to polymerize over time. This polymerization results in the
formation of a high boiling point material which will have a negative effect on
reformer yields as a result of excessive coking. The existing guard bed reactor
located on the 1344 reformer site currently used to remove silica will be
converted to hydrotreating service and placed in series with the existing
naphtha hydrotreater, thereby increasing the effective reactor volume of the
naphtha hydrotreater.
Other offsite modifications will be made consisting of inter-connecting
piping, addition of a flare, modifications to the fire water system, addition
of electrical distribution systems, a new cooling tower, and site improvement.
Clark plans to receive a minimum of 125,000 bpsd of crude oil at the Refinery
docks. A study was performed by Lanier & Associates, a marine engineering and
consulting firm, which concluded that Clark's dock facilities are adequate to
support the required capacity. The remainder of the crude oil will be delivered
to the Sun terminal at Nederland which is located approximately 15 miles from
the Refinery from where the crude oil is sent by Clark's pipeline to Clark's
Lucas terminal. The crude oil is shipped from the Lucas terminal to the
Refinery via a company-owned pipeline. The Sun terminal, which has five ship
docks, three barge docks and approximately ten million barrels of storage
capacity, can receive all 250,000 bpsd of crude oil if necessary and the
pipeline can transport this quantity to the Refinery. Clark and Chevron/Gulf,
the owner of the Refinery
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prior to Clark, have had a long term relationship with the Sun terminal and PGI
sees no reason that the availability of the Sun terminal would change. Clark
utilizes the Sun terminal under a year to year evergreen contract. PGI believes
that the crude import facilities are adequate to accommodate the volumes of
crude oil contemplated for the Upgrade Project's operation.
If, for some unforeseen reason, the Sun terminal would not be available or
would have reduced capacity, the Refinery would have other alternatives. A
Unocal terminal, also located at Nederland, is connected to an idle Chevron
pipeline which could easily be connected to the Lucas terminal. This terminal
has 6.2 million barrels of storage and two ship docks. The Refinery also has
access to the Louisiana Offshore Oil Port through a Texaco pipeline which could
be used to transport approximately 100,000 bpd.
UPGRADE PROJECT COSTS
A definitive Upgrade Project construction cost estimate including both the
EPC Contract and the Clark EPC Contract has been prepared by Foster Wheeler and
Clark. PGI's review of this cost consisted of an evaluation of each major cost
category, in comparison with similar cost categories for other United States
Gulf Coast projects.
The total construction cost for the Upgrade Project is $636 million,
excluding working capital, financing expenses, capitalized interest, and
owner's costs. This includes the PACC EPC Contract of $544 million and $92
million for the Clark EPC Contract. The cost of the major new PACC units and a
portion of the offsites are incorporated in the EPC Contract, while the Clark
portion of the revamps and offsites will be incorporated in the Clark EPC
Contract. An itemization of the construction cost is shown below.
TABLE IV-1
UPGRADE PROJECT CONSTRUCTION COST ESTIMATE
(Million $)
<TABLE>
<CAPTION>
EPC Clark EPC
Contract Contract Total
-------- --------- -----
<S> <C> <C> <C>
New Units (coker, hydrocracker, SRU)............. 442 0 442
Existing unit revamps............................ 0 44 44
Offsites......................................... 27 48 75
Contingency, Escalation, and Profit.............. 55 -- 55
Spare Parts, Other............................... 20 -- 20
--- --- ---
544 92 636
</TABLE>
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Other Upgrade Project costs borne by both Clark and PACC include items such
as Upgrade Project management team expenses and salaries, insurance, startup
costs, training, legal and other miscellaneous costs that are not covered by
the EPC Contract. The $52 million allowance for other PACC costs, not including
contingency, appears to adequately cover the expected categories. An additional
contingency of $28 million has been included with this estimate. The breakdown
of the other PACC Project cost estimate is shown below.
TABLE IV-2
UPGRADE PROJECT OTHER COST ESTIMATE
(Million $)
<TABLE>
<CAPTION>
PACC CLARK TOTAL
---- ------- -----
<S> <C> <C> <C>
Project Management Team.............................. -- 26(/1/) 26
Startup Costs, Taxes................................. 20 -- 20
Legal and Consulting................................. 11 2 13
Financing Expenses................................... 21 -- 21
Contingency.......................................... 28 -- 28
--- ------- ---
80 28 108
</TABLE>
(1) Includes construction management fees of $7 million to be repaid to Clark
by PACC over 3 years following startup.
The total Upgrade Project cost estimate is $833 million ($636 million in
construction cost, $108 million of other Upgrade Project costs and $89 million
of capitalized interest expense). Based on its analysis of the construction and
other Upgrade Project cost, PGI believes that the budget will be adequate based
on comparison to similar construction in the United States Gulf Coast region in
recent years and based on the fact that 98% of major equipment has been
procured, design is 70% complete and site excavation and foundation work is
well advanced. The Upgrade Project contingency and escalation allowance is
sufficient, excluding excessive discretionary changes or force majeure events.
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UPGRADE PROJECT SCHEDULE
Upgrade Project mechanical completion is based on a 31-month schedule from
the start date of April 1, 1998, which PGI feels is achievable.
[Chart of Figure IV-2 Project Schedule]
The key Upgrade Project milestones defined in the EPC Contract are as
follows:
<TABLE>
<CAPTION>
Milestone Date
------------------- ------------------------
<S> <C>
Target Mechanical
Completion November 1, 2000
Guaranteed
Mechanical January 1, 2001
Completion (start of delay damages)
Mechanical
Completion Default March 1, 2001
Substantial
Reliability
Default September 1, 2001
Guaranteed Final
Completion December 1, 2001
</TABLE>
The 60-day Reliability Test is planned to be carried out as soon as possible
after PACC Project startup and stable operation. Achievement of Substantial
Reliability in the Reliability Test must occur before September 1, 2001.
Guaranteed Final Completion or debt buydown must occur prior to December 1,
2001.
The delay damages and performance damages applicable are discussed in EPC
Contract section of this report.
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TECHNOLOGY ASSESSMENT
The selected technology for the processes that form the Upgrade Project are
typical of the preferred processes currently used in the industry and are well
integrated into the existing Refinery. In all, PGI believes that the Upgrade
Project will be able to perform as planned based on the technology selected.
Each major unit or category of the Upgrade Project is discussed below.
DELAYED COKER
The processing design selected by Clark to upgrade heavy sour Maya crude oil
consists of a delayed coker and VGO hydrocracker integrated with Clark's
existing processing units. This design is widely accepted in the industry as
the preferred method of upgrading heavy sour crude oils like Maya. PGI believes
that Clark has chosen well proven technology to upgrade Maya crude oil that
will result in the planned yields and economics.
Delayed coking technology has been utilized for well over 50 years and is one
of the most widely used processes to upgrade low value heavy residue into
higher value light products. The process is based on the principle of severe
thermal cracking which essentially breaks high molecular weight molecules into
lower molecular weight molecules via high temperatures. The portion of the
residue that does not crack is left as coke which is a coal-like solid material
and, in the case of coke derived from Maya crude oil, is typically burned as a
fuel. The delayed coking process incorporates specially designed high velocity
heaters which minimize coke formation in the heaters. The heater effluent flows
into the coke drums where the coking reaction takes place and hydrocarbon
vapors are vented to a fractionator. The delayed coking process is considered a
semi- batch process because once a coke drum is full it is taken off-line and
the heater effluent is switched to another coke drum. The heads of the drum are
then opened and the coke is drilled out of the drum using a high pressure water
jet. The hydrocarbon vapors leaving the coke drum during normal operation are
fractionated yielding a fuel product, a propane/propylene product, a
butane/butylene product, a naphtha product which is sent to the catalytic
reformer, a light gas oil product which is blended to the diesel pool after
hydrotreating, and a heavy gas oil product which is sent to the hydrocracker.
The delayed coker being constructed is a modern Foster Wheeler design
incorporating a low operating drum pressure and a low recycle rate. A lower
operating pressure results in more favorable product yields and a lower recycle
rate which reduces unit operating costs.
The delayed coking technology will be provided under a license with process
guarantees from Foster Wheeler in the EPC Contract. Foster Wheeler is a very
experienced licensor of delayed coking technology having designed over 100
coker units, representing an 80% market share, with the largest being 120,000
bpsd. Although the 80,000 bpsd coker is fairly large in size, Foster Wheeler
has designed five units with a capacity of 75,000 bpsd or greater. Two of these
have been in operation for several years and three others are under
construction. The key equipment items of a delayed coker are the coke drums and
coke drum size is limited by the ability to cool the coke during the decoking
cycle. Recent unit designs, including the PACC coker, have required larger coke
drums to achieve design rates. The coke drums being utilized for the PACC coker
are similar in size to two recent Foster Wheeler projects and have a proven and
successful operating history.
VGO HYDROCRACKER
Hydrocracking VGO is also a well proven technology of upgrading VGO to
lighter, more valuable products. The hydrocracker employs fixed bed catalysts
with high pressure hydrogen to crack heavy feedstock into lighter, more
valuable products. In addition, the sulfur concentration of the products is
reduced to very low levels as compared to the feed.
The hydrocracking process design is licensed from Chevron who also provides a
process guarantee. Chevron has conducted pilot plant testing on the proposed
PACC feedstocks and has verified the projected yields and process conditions.
The pilot plant testing provides credibility to the hydrocracker yields assumed
in the Base Case and PGI believes that the projected yields can be achieved.
SULFUR RECOVERY
The new 417 LTD SRU will operate in parallel with existing units and is
designed to recover 99.8% or greater of the hydrogen sulfide in the feed gas.
Amine acid gas and sour water stripper acid gas are routed to a Claus SRU using
technology licensed from Amoco Corporation. The tailgas from the Claus sulfur
plant is
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processed using the SCOT process, licensed by Shell Oil Company, to produce an
acid gas stream that is recycled back to the Claus plant to achieve the desired
recovery. The effluent gas from the SCOT Tailgas Cleanup Unit is thermally
incinerated in a Tailgas Thermal Oxidation Unit to convert all of the remaining
sulfur compounds into sulfur dioxide (S0\\2\\) before dispersion of the gas to
the atmosphere. The effluent gas from the SRU and SCOT is expected to comply
with the regulatory requirements for sulfur plants operated in Texas
refineries.
The SRU is being designed by a joint team of Ortloff Engineers, Ltd. (process
and technology) and Pro-Quip (engineering and construction) under the
supervision and responsibility of Foster Wheeler. Ortloff and Pro-Quip have
often worked together over the past ten years to design and construct a variety
of sulfur recovery systems. PGI believes that the technology selected for the
SRU and the Ortloff/Pro-Quip team will deliver a well-designed unit with
adequate sulfur removal capacity to support both the Clark Project and PACC
Project operation at full capacity.
The Sour Water Stripper and Amine Treating Unit are generic open art units
that were designed by Jacobs Engineering Group ("Jacobs") and will be
constructed by Matrix Engineering under Foster Wheeler's supervision and
responsibility. These units are commonly found in all refineries and do not
involve any unique technology. PGI has reviewed the design basis for these
units and believes that the units will be adequate for the purpose intended.
REFINERY RENOVATIONS AND UPGRADES
The majority of renovation and upgrade capital will be spent on upgrading the
existing crude unit to process primarily Maya crude oil and to increase
capacity by about 10% from 232,000 bpsd to 250,000 bpsd. The revisions involve
addition of heat exchangers, re-configuration of piping, replacing pumps,
replacing vacuum tower packing, and adding tubes to the vacuum tower heater.
These activities are of the type that are typically carried out by refineries
during turnarounds. The process design has been carried out by Jacobs and
Foster Wheeler under Clark's supervision. The majority of the crude unit work
is to be conducted during a turnaround scheduled for March 2000. PGI believes
that the crude unit design is adequate to support the processing of the
proposed volume of Maya crude oil required to support the PACC and Clark
operations and that these revisions will be completed before Project start-up.
The GFU-241, GFU-242 and GFU-243 distillate/kerosene hydrotreaters are being
upgraded to increase capability for handling the higher sulfur distillate
products produced from the more sour crude slate. The modifications involve
increasing the size of reactors and catalyst volume through replacement of
reactors. These types of small debottlenecking projects are routinely carried
out in refineries. A portion of this work (GFU-243) has already been completed.
PGI believes that the hydrotreater revamps will be adequate to support the PACC
and Clark's operations and that these are estimated to be completed three to
six months prior to PACC Project start-up.
OFFSITES, AND UTILITIES
The major activities to be carried out in this category are
. Interconnecting process and utility piping pumping between the new units
and the Refinery
. Upgrade of crude pumping station
. Conversion of Tanks 108 and 109 to coker feed storage
. Coke handling outside battery limits of PACC
. Addition of piping and pumps to feed new sour water stripper
. Provision of a new cooling tower to provide cooling water to both Clark
and PACC
. Construction of a new dedicated flare for the new units
. Construction of a new 13.8 kV substation to supply power to the new
units. Additional power to the Refinery will be supplied from the APCI
hydrogen plant and Entergy
. Install truck and rail loading facilities for sulfur
. Construction of a new control building for the new units
. Expansion of the firewater loop to the new units
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The offsites and utilities items are a collection of typical refinery
projects. The majority of the capital is for the interconnecting piping and
electrical substation. PGI has reviewed the design basis for these items and
believes that the planned offsites and utilities will be adequate for both the
Clark Project and PACC Project. PGI further believes that the offsite and
utilities items do not pose a major technological or construction delay risk to
Clark or PACC.
PROJECT CONTRACTS
CRUDE OIL SUPPLY AGREEMENT
In March 1998, Clark signed the PMI Contract with PMI. The PMI Contract is
designed to provide a stable and secure supply of Maya crude oil to PACC for
over eight years commencing upon completion of the Upgrade Project. The PMI
Contract incorporates the use of a formula that acts as a proxy for calculating
the difference between light products and heavy oil or resid prices. The PMI
Contract provides stabilization for this differential for up to 210,000 bpsd of
Maya crude oil. The Base Case assumes a Contract Quantity of 160,908 bpsd.
Pricing--The base price of Maya crude oil is the formula price used by PMI to
price the majority of PMI Maya crude oil sales. The formula price of Maya crude
oil is stated as follows and is a 5-day average of the formula components:
Maya Price = 0.40* (WTS + FO No. 6, 3%S) + 0.10*(LLS + Brent DTD) - DF
where WTS = the average Platt's prices for West Texas Sour crude oil,
$/B
LLS = the average Platt's prices for Light Louisiana Sweet crude
oil, $/B
Brent DTD = the average Platt's prices for Brent Crude Oil, $/B
FO No. 6, 3% S = the average Platt's prices for fuel oil having 3%,
sulfur content $/B
DF = discount factor subject to adjustment by PMI, $3.50/B at time
of signing
For WTS, LLS and Brent, the price is the average of the high and low spot
prices as quoted by Platt's Crude Oil Marketwire. For FO No. 6 Fuel Oil, the
price is the average of the high and low spot prices as quoted by Platt's
Oilgram U.S. Marketscan, U.S. Gulf Section, Waterborne Column.
The PMI Contract provides for an alternative mechanism for calculating the
price of Maya crude oil under certain conditions where there is a lack of
adequate buyers of Maya and the formula price is not able to be confirmed in
the market. The alternative pricing methodology calculates the price of Maya
based on a marker crude oil, gasoline, diesel, and No. 6 fuel oil through the
use of a multiple regression formula where the coefficients of the regression
formula are based on historical pricing. If the formula price of Maya deviates
sufficiently from the predicted price of Maya using the multiple regression
technique, then the multiple regression formula will be used to determine the
price of Maya. The marker crude oil used in the regression formula can be any
actively traded crude with similar properties to Maya (although it does not
need to be a heavy sour crude) with transparent pricing, significant USGC
market depth, and widely available published pricing.
Differential--The Differential is incorporated into the PMI Contract to
provide PACC with a stabilized average coker gross margin. This is effected
through the application of a discount to the market price of the Maya crude oil
when the Differential falls below a negotiated floor of $15 ("Guaranteed
Differential") or through the application of a premium when the Differential
exceeds $15. The Differential formula is defined as follows:
Differential = (0.5*RUL) + (No. 2 Oil) - (1.5*No. 6 Oil)
where RUL = average of Platt's prices for conventional, non-RFG 87
octane gasoline, $/B
No. 2 Oil = average of Platt's prices for 0.2% sulfur No. 2 fuel oil,
$/B
No. 6 Oil = average of Platt's prices for 3% sulfur No. 6 fuel oil, $/B
Prices are calculated on a monthly average based on the low spot prices
in the U.S. Gulf Section, Pipeline column of Platt's Oilgram Price
Report for RUL and No. 2 oil and the Waterborne column for No. 6 oil.
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On a monthly basis the difference between the Differential and the Guaranteed
Differential is calculated. If the Differential is greater than the Guaranteed
Differential, then a monthly surplus exists. If the Differential is less than
the Guaranteed Differential, a monthly shortfall exists. At the end of a given
quarter, the monthly shortfalls and surpluses are netted. If a net shortfall
exists, then PACC will receive a discount on crude oil in the succeeding
quarter equal to 36.6% (the typical percentage of coker feedstock derived from
one barrel of Maya processed through the crude unit) of the net shortfall times
the Contract Quantity times the number of days in the quarter (assumed to be 90
days) up to a maximum $30 million in any given quarter. Any excess of this
amount will be carried to the next quarter with interest applied. Conversely,
if a net surplus exists, then Clark will pay a premium on the crude oil
received in the succeeding quarter equal to 36.6% of the net surplus times the
Contract Quantity times the number of days in the quarter limited to a maximum
of $20 million in any given quarter, subject to PACC having an aggregate
shortfall position at the end of the prior quarter. As above, any excess of the
$20 million cost will be carried to the next quarter with interest applied. The
total premium paid by PACC will not be greater than the aggregate of discounts
received in prior quarters plus interest. Interest is applied quarterly at a
rate of LIBOR + 1% on the aggregate of discounts received in prior quarters.
Duration--The PMI Contract has an eight year Differential period. The
Differential period commences upon the earlier of (1) Upgrade Project
completion, which is defined in the PMI Contract as having achieved mechanical
completion, commissioning and processing at a rate of at least 80% of Refinery
and coker design capacities for at least thirty consecutive days and (2) July
1, 2001, which date may be extended for reasons of force majeure. If the
Upgrade Project has not reached these completion criteria by January 1, 2001,
monthly extensions can be purchased. Either PMI or PACC have the right to
terminate the PMI Contract after eight years subject to a minimum one-year
phase out period.
Force Majeure--The force majeure clause in the PMI Contract includes as part
of the definitions "interruption, decline or shortage of Seller's supply of
Maya available for export from Mexico (including, without limitation, shortage
due to increased domestic demand)". This clause is standard for PMI oil supply
agreements and would presumably allow PMI to invoke force majeure if Mexican
refinery demand for Maya increased more rapidly than production. In PGI's
knowledge, this aspect of the force majeure clause has not been exercised with
other buyers of Maya crude oil. Based on its crude oil supply/demand forecast,
PGI does not expect this clause to be invoked during the term of the PMI
Contract. PGI does expect relatively constant projected domestic demand for
Maya, while large increases in Maya production are planned.
According to the PMI Contract, any reduction in PACC's Maya supply volume
would be in proportion to total reductions in Maya supply to other large
quantity Maya customers, or if too few, then to industry. PACC would not be
disadvantaged compared to other contract buyers of Maya crude oil.
Pricing Forecast and Effect on PMI Contract
The PMI Contract was reviewed by PGI utilizing PGI's oil and refined products
price forecast. The Differential formula was applied with pricing discounts and
premiums applied as appropriate.
Figure IV-3 illustrates the PGI forecast of the calculated Differential
formula compared to the Guaranteed Differential. The Differential formula is
designed to be managed quarterly; however, PGI's forecast is made on an annual
basis only and therefore the Differential formula was applied annually as well.
As can be seen in the figure, a net shortfall situation exists in 2001 and
2002, the first two full years of operation, where PACC receives a discount.
After 2002 and onward, the Differential formula moves to a net surplus
position. A premium is applied in 2003 through 2006 equal to the aggregate
discount received by PACC in 2001 and 2002 plus interest at a rate of LIBOR +
1%. From 2007 forward, PACC is forecast to pay the market price for Maya crude
oil since the remainder of the Differential formula period results in a net
surplus position.
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[Chart of Figure IV-3 PMI Contract Guaranteed Differential]
These results are not surprising and confirm that the basic intent of the PMI
Contract is only to minimize adverse cycle risk to secure adequate cash flow
for debt service obligations. It is not structured as a permanent subsidy for
oil purchases. Figure IV-3 confirms that the parties to the PMI Contract have
chosen an appropriate level for the margin protection which should not put
unfair pressure on PMI over an extended period of time.
APCI HYDROGEN CONTRACT
APCI and PACC will enter into a twenty-year take and pay, if delivered
contract under which PACC will purchase up to 80 million standard cubic feet
per day ("MMSCFD") of hydrogen from APCI, of which 55 MMSCFD will be on a
dedicated take and pay basis. APCI will build a new steam methane reformer and
two PSA purification units on Refinery property leased from Clark. APCI will
also produce steam and electricity for sale to Clark.
Commencement date of the contract is required to fall between October 6, 2000
and December 6, 2000 (the "Start-up Date"). PGI believes that the Start-up Date
is achievable. If the hydrogen supply plant fails to be ready to operate due to
APCI acts or omissions on or before December 6, 2000 or prior to December 6 if
the PACC Project requires hydrogen due to completion of the PACC Project, APCI
will pay liquidated damages of $19,250 per day for each day of delay up to
$1,155,000. If PACC is unable to take the hydrogen on or before December 6,
2000 then PACC will pay liquidated damages of $38,500 per day for each day of
delay up to $1,155,000. APCI will guarantee that the hydrogen supply will
achieve an on-stream factor of at least 98% and will pay liquidated damages up
to $1,800,000 if the on-stream factor falls below 98%. If APCI achieves an
average on-stream factor greater than 98%, the APCI will be eligible for a
bonus of up to $900,000. Penalties or bonus payments due to on-stream
reliability will be determined after two complete years of operation.
The hydrogen price is set from an initial base natural gas price and then
adjusted monthly for natural gas price, a labor cost index and the producer
price index. The pricing mechanism is market based and is typical for U.S. Gulf
Coast hydrogen contracts. The price is consistent with the hydrogen price
utilized in the Base Case. PGI believes that the Hydrogen Contract provides
hydrogen and utilities at a competitive price and adequate volume to PACC.
REVIEW OF INTERCOMPANY AGREEMENTS
There are four Intercompany Agreements between Clark and PACC. These are:
. Coker Complex Ground Lease And Blanket Easement Agreement--Land lease for
site of PACC units and access to common facilities by PACC.
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. Ancillary Equipment Site Lease And Easement Agreement- Lease of Clark
owned units.
. Product Purchase Agreement--Clark purchase of products produced by PACC
. Services and Supply Agreement--Supply of all required services and
utilities by Clark to PACC and fees paid by Clark to PACC for processing
Clark crude oil through all PACC owned and leased units
The intent of the Intercompany Agreements is to transact access, supplies,
services and product purchases to reflect arms-length market mechanisms and
fair market pricing terms.
Coker Complex Ground Lease and Blanket Easement Agreement
("Ground Lease")
The Ground Lease provides for the leasing to PACC of land and any
improvements located on such property encompassing the sites for the coker,
hydrocracker and SRU. Clark also grants easements to PACC for access across the
Refinery including ingress, egress, piping, wiring and other purposes as
necessary. An additional easement is provided for use of the Refinery dock for
unloading crude oil and feedstocks and for loading of products.
Under the Ground Lease, Clark also grants PACC a license to use various other
facilities at the Refinery required for operation of PACC.
The payment for the Ground Lease is structured as an up-front payment of
$25,000 for the initial 30 year term of the lease. Any lease extensions will be
based on a fair market rental value as agreed between Clark and PACC or by a
value determined according to the defined appraisal procedure contained in the
Ground Lease definitions. The Ground Lease can be extended past the initial 30
year term in 5 year increments. At the end of the Ground Lease, any
improvements may be dismantled and removed by PACC or, if not removed, shall
become the property of Clark.
Ancillary Equipment Site Lease and Easement Agreement
("Ancillary Equipment Lease")
The Ancillary Equipment Lease is an agreement between Clark and PACC covering
PACC's lease of the site where the Ancillary Equipment is located, access to
the Clark owned process units. In PGI's opinion, this agreement is critical for
PACC to operate in a stand-alone, as well as, the normal mode of operation. The
process units and offsites included in the Ancillary Equipment Lease are:
. Crude/vacuum unit, AVU-146
.Hydrotreaters, GFU-242, GFU-243, CRU-1344
The Ancillary Equipment Lease also grants easements to the PACC for required
access to the leased facilities.
Clark is upgrading the crude and vacuum units to increase processing capacity
from 232,000 up to 250,000 bpsd. Clark is obligated to substantially complete,
at its sole cost, upgrades on or before October 1, 2000. After start-up of the
PACC-owned units, PACC will pay to Clark quarterly lease payments of
approximately $8 million adjusted for inflation through the lease term. An
operating fee determined in accordance with the fixed and variable costs for
Clark processing PACC's crude oil through the Ancillary Equipment is due
monthly. The quarterly lease fee is based on a capital recovery charge for both
existing asset values and the cost of the upgrade. PGI has reviewed the cost of
the lease and operating fees and believe they reflect arm's length basis
pricing and fair market terms.
The initial term of the Ancillary Equipment Lease is for a 30 year period.
The agreement allows for five 5-year extensions. The rent for any extension
period will be based on a fair market rental value as agreed between Clark and
PACC or by a value determined according to the defined appraisal procedure
contained in the agreement definitions.
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Product Purchase Agreement
The Product Purchase Agreement ("PPA") provides for the sale to Clark of all
the finished and unfinished products produced by PACC. The agreement is a take
and pay, if delivered contract and as such obligates Clark to accept and take
delivery of all the products that are produced by PACC and delivered to Clark.
In the event that Clark cannot take delivery, PACC has the right to sell the
products to a third party.
Products are sold based on market based pricing using industry market indices
such as Platt's and Oil Price Information Service ("OPIS"). Intermediate or
unfinished products are discounted for quality considerations and both finished
and intermediate products have appropriate charges for marketing and
terminaling costs when these products are sold to third parties. PGI reviewed
the pricing methodology applied in determining the product values and considers
it to be industry typical and to reflect arm's length basis pricing and fair
market terms. PGI also verified that the product pricing contained in the PPA
is consistent with the pricing used in the Base Case projections. All products
have required target specifications, delivery points, quantity, measurement,
and quality references.
The contract term is for a 30 year period and therefore extends well beyond
the term of the financing. The agreement addresses the required product mix to
be produced and states that any changes made must maximize the overall Refinery
profitability and cannot maximize Clark's profits at the expense of PACC.
The PPA is structured to work in conjunction with the Services and Supply
Agreement. If any dispute arises regarding the PPA, PACC and Clark are required
to meet and resolve the conflict. In the event an agreement is not reached
either party may initiate an arbitration proceeding.
Services and Supply Agreement
The Services and Supply Agreement ("SSA") incorporates all the services and
supplies that Clark provides to PACC including the following: (i) management
and supervision of the PACC construction; (ii) supervision, management and
maintenance of the required Ancillary Equipment (crude/vacuum and
hydrotreaters) needed by PACC to generate on a continuous basis the required
product mix as defined in the PPA; and (iii) provision of services, supplies
and certain feedstocks to PACC.
The SSA has a 30 year term and gives PACC the right to terminate the
agreement for an event of default that is not remedied by Clark. The agreement
provides for Clark arranging for PACC the delivery of Maya and light sour crude
oils and other Refinery feedstocks including hydrogen, provides dock, pipeline,
and storage services, enables Clark and PACC to arrange for processing of their
crude oils and products in the respective PACC and Clark facilities, supplies
operations, management, technical, and maintenance personnel, supplies all
required utilities, chemicals and catalysts,and fuel, and arranges for all the
support services needed to operate PACC in regulatory compliance as well as
safely and reliably.
The SSA also contains provisions addressing the processing rights by Clark
for the use of its required capacity in either PACC-owned units or the
Ancillary Equipment. The agreement also grants PACC approval rights with
respect to annual budgets and operating plans submitted by Clark. These
provisions protect PACC's ability to generate revenues and its profitability.
Each of the services mentioned above are tied to specific schedules that
describe the specific service to be provided and address quantity, measurement,
applicable pricing, and billing. Both PACC and Clark are obliged to make the
required payments that cover the reimbursable costs incurred by the party
providing the service and/or supply. PGI reviewed the pricing methodology
applied in determining the specific services and/or supply to be provided and
consider it to reflect arms-length basis pricing and fair market terms. PGI
also verified that the revenues and expenses as a result of these services and
supplies are reflected in and consistent with the Base Case.
The SSA is structured to work in conjunction with the PPA. If any dispute
arises regarding the SSA, PACC and Clark are required to meet and resolve the
conflict. In the event an agreement is not reached either party may initiate an
arbitration proceeding.
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ENGINEERING, PROCUREMENT, AND CONSTRUCTION CONTRACTS
There are two separate contracts with Foster Wheeler: (i) the Clark EPC
Contract between Clark and Foster Wheeler; and (ii) the EPC Contract between
PACC and Foster Wheeler. Following is a summary discussing each one.
Clark EPC Contract
The renovation and upgrade of the crude unit, vacuum tower and other
Ancillary Equipment required to be performed by Clark pursuant to the Ancillary
Equipment Lease represents primarily routine turnaround work and will be done
by Foster Wheeler under the Clark EPC Contract. Under this contract, Foster
Wheeler is paid on a "cost-plus" reimbursable basis rather than a fixed-cost
basis. The cost estimate for this work is $92 million. PGI expects completion
of this work to occur no later than October 2000. This contract contains
retainage, warranty and process guarantee provisions from Foster Wheeler that
are customary for reimbursable-cost basis refinery upgrade contracts. This
contract will be assigned to PACC as security for Clark's construction
obligation under the Ancillary Equipment Lease.
EPC Contract
The EPC Contract is a lump sum fixed price basis contract for the
engineering, design, procurement, construction, installation, testing and
documentation of a new 80,000 bpsd delayed coking unit, a 35,000 bpsd
hydrocracker, a 417 LTD sulfur recovery unit and various offsites for a fixed
price contract amount of $544 million.
The EPC Contract in most aspects follows a typical industry standard format
that is routinely used for a lump sum fixed price basis agreement. In addition
it incorporates substantial terms and conditions pertaining to completion and
acceptance (covering performance and reliability) that is more demanding of
Foster Wheeler. The engineering, procurement, and construction of the PACC
process units (delayed coker, hydrocracker, amine and sour water stripper, and
sulfur plant) are on a fixed price basis. The EPC Contract specifically defines
the scope, deliverables, responsibilities, obligations, price, and schedule.
PGI believes that the EPC Contract will provide the PACC with a well designed
facility and a reliable operation. The EPC Contract contains the mechanism
required to control the cost and completion dates, and is structured to reduce
the risks associated with overruns, schedule delays and integration with the
process units outside of PACC that are needed for the continuous operation. It
also incorporates the auditing requirements which will be carried out by the IE
who will independently monitor construction and certify completion and
performance.
Following are some specific comments pertaining to some of the more critical
contract terms and conditions.
Contractor Responsibilities
In general terms, the EPC Contract protects PACC's rights, and obligates
Foster Wheeler to meet all its obligations and responsibilities in the
engineering, procurement, construction, commissioning, and startup of the
Upgrade Project. Clark management has provided specifications ("Turnkey
Specifications") which Foster Wheeler is contractually obligated to meet in the
performance of their responsibilities. The EPC Contract language is very
specific and careful in making Foster Wheeler, and solely Foster Wheeler,
responsible for all obligations under the EPC Contract including completing
construction within a fixed price and project schedule, including all work
performed by subcontractors.
Foster Wheeler non-performance is penalized by rebates and setoffs. These in
turn are related to delay and performance liquidated damages caused by delays
in mechanical completion or under performance when PACC cannot achieve process
design guarantees and reliability criteria defined in a Performance Test. Delay
damages amounting up to $70 million and performance damages amounting up to $75
million are specified in the contract. The Performance Test includes both a
Capacity Test and a Reliability Test. Performance Test liquidated damages are
applicable if and when PACC is not able to operate at design capacity or
produce the
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specified salable products, or achieve the guaranteed plant efficiency. In
addition, the Reliability Test requires Foster Wheeler to demonstrate that PACC
can achieve minimum daily net margin targets. In the event the daily net
margins are not achieved, Foster Wheeler is obligated to make Reliability Test
buydown payments. While the EPC Contract does contain a clause allowing the
payment of a bonus in the event of early completion, it is only paid upon final
acceptance of the Upgrade Project. The contract also subjects Foster Wheeler to
a penalty equal to the full amount of the contract, i.e. $544 million in the
event of default.
Scheduled payments will be based on achieving determined engineering,
materials procurement, and construction progress. PGI will be required to
review the Upgrade Project's progress in relation to expenditures. In addition
to delay and performance liquidated damages, the contract requires a 10% letter
of credit that serves as a retainage in which PACC is the beneficiary and has,
as owner, the right to withhold funds in the event of Foster Wheeler not
completing all items as required in the Turnkey Specifications.
Project Cost and Schedule
The EPC Contract has terms that address fixed price and firm completion
dates. The terms and conditions typically found in EPC fixed price contracts or
LSTK arrangements that allow either cost or schedule increases, are included in
the EPC Contract. Specifically, changes in laws or regulations, force majeure
situations, and change orders are part of the EPC Contract and are drafted in
detail. Sufficient site work has been completed at the Refinery to eliminate
unknown underground structures risk, which is sometimes an additional cause for
change orders, and make this the responsibility of Foster Wheeler.
PGI believes that the cost estimate as well as the construction schedule are
both very realistic and achievable, that the risk allocation is fair and should
not result in cost increases or disputes.
Changes in Laws or Regulations
In PGI's opinion, changes in laws or regulations should be of little impact
since Clark has obtained revised permits needed for PACC construction. Further
details on the construction permits are contained in the Environmental Section
of this report.
Force Majeure and Owner Delays
The force majeure clause is considered typical of those found in EPC
contracts, and should not be a cause for construction project overruns or
schedule delays. The intent of the EPC Contract is that Foster Wheeler be a
qualified contractor (as addressed in the Contractor's Expertise clause) who is
experienced in doing similar projects and is familiar with the location where
construction is to take place. Language in the force majeure section restricts
extraordinary weather related delays by specifying a 30 year history and limits
labor problems to industry wide and/or nationwide incidents. PGI believes that
Foster Wheeler has taken into account its experience in refinery projects and
knowledge of the Port Arthur region, and built in sufficient time for
uncontrollable events that may occur during the course of the construction
which may have an impact on construction cost and schedule.
The EPC Contract also addresses owner caused delays which can be the basis
for contractor claims. Clark management and Foster Wheeler have organized an
experienced team, which in our opinion is critical to having a successful
Upgrade Project. Clark management is committing sufficient personnel as needed
to undertake the Upgrade Project management and support Foster Wheeler efforts.
Based on our meetings with Clark management and Foster Wheeler, we believe that
sufficient capable and experienced human resources and planning are (and will
be made) available, as needed, to achieve successful completion of the Upgrade
Project.
Change Orders
Change orders can be a major cause for cost overruns and schedule delays.
Change orders can be avoided if specifications are very clear and do not have
any undefined scope or responsibilities. As currently drafted,
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<PAGE>
PACC has the right to approve or disapprove change orders at its option. In
PGI's opinion, the EPC Contract includes satisfactory terms to provide a
comprehensive and complete technical specification to the contractor and to
provide sufficient supervision and controls to minimize the potential for
change orders. PGI must approve any individual change order in excess of
$500,000 and change orders, in the aggregate, in excess of $5 million.
Based on the advanced design (over 70% complete as of June 1999), 98%
completed procurement, civil construction being almost finalized and the
remaining construction time of 16 months, the risk of excessive and expensive
change orders is considered minimal.
Warranties
The objective of the EPC Contract is to deliver a facility that performs
according to design. A facility that is completed on time and within budget but
does not perform according to design would be of little value. Sufficient
safeguards in the form of warranties and performance guarantees are needed
beyond mechanical completion, commissioning, and startup to assure a safe,
reliable, and profitable operation. The EPC Contract contains language on
mechanical warranties and performance guarantees that cover all defects and
deficiencies caused by errors and omissions in engineering and design or
otherwise. The warranties vary from one to three years and cover civil and
mechanical events. The mechanical warranties vary from one to two years
depending on mechanical completion dates and are considered typical for EPC
contracts. The guarantees cover plant capacity, efficiency, reliability, and
the integration of the PACC Project with the rest of the Refinery. In PGI's
opinion, these warranties and guarantees are adequate.
Performance Tests and Completion Guarantee
The EPC Contract addresses both delay penalties and performance penalties.
Delay penalties cover delays in mechanical completion while performance
penalties cover performance at below design conditions.
Delay damages are triggered if Foster Wheeler does not achieve mechanical
completion or Guaranteed Reliability by the Guaranteed Mechanical Completion
Date (as defined in the EPC Contract) by January 1, 2001 and if certain other
milestones are not met after the PACC Project is mechanically complete. The cap
of $70 million for delay damages is sufficient to cover non-capitalized debt
service payments through December 31, 2001.
The EPC Contract incorporates performance tests that confirm PACC's
capability to process the required amount of feedstocks, produce the design
product yields and specifications, and consume the energy (fuel and
electricity), and utilities, as specified in the operating assumptions of the
Base Case economic model. Foster Wheeler guarantees completion and has to pass
a sixty-day extended period test that will reflect the various unit capacities
to achieve operation at process design conditions. Each unit must operate
smoothly in a safe and efficient mode and in environmental compliance for
extended periods that demonstrate its reliability over the long term. Tables
IV-3 through IV-7, Performance Test Standards, show how the performance is
validated. If the Performance Test fails to achieve the Guaranteed Reliability
(as defined in the EPC Contract), Foster Wheeler is subject to loan buydown
payments, for up to $75 million. This buydown amount is considered by PGI to be
adequate to cover the majority of foreseeable risks.
In addition, Foster Wheeler is exposed to 100% of the EPC Contract amount
until PACC achieves Substantial Reliability which is defined as 95% of the
Guaranteed Reliability as defined in the EPC Contract.
PGI believes that the definition, configuration and duration of the agreed
performance and reliability test are suitable to demonstrate that PACC will be
able to achieve the operating rates and efficiencies assumed in the Base Case
and that these tests and other rights that PACC has under the EPC Contract
represent an appropriate completion risk mitigation.
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<PAGE>
Independent Engineer
The EPC Contract includes provisions which address the role of an IE. The IE
participates in reviewing the procedures and practices followed in the
engineering, procurement, and construction phases of the Upgrade Project.
Although the IE does not perform or participate in any process simulations,
equipment specifications, mechanical drawings, piping and instrument diagrams,
civil and structural design, fabrication, and construction activities, the IE
provides an opinion on whether the engineering and construction is following
standard industry practices, required implementation policies exist, an
experienced and qualified management team is in place, sufficient checks and
balances exist, and that any specific requirements are in place. The IE is also
responsible for certifying that the required steps are being taken by the
management team to assure that the Upgrade Project is being designed and built
in accordance with the required standards and within the allotted budget and
schedule. In the event that any problems are detected, the IE is responsible
for bringing these to the attention of the Financing Parties as well as PACC
management.
Construction Monitoring
While it is PACC's responsibility to review and certify that each EPC
Contract invoice is valid and is due, the IE will monitor the construction
progress (by reviewing periodic progress reports and making routine visits to
the construction site) and will certify to the disbursement agent that
construction funds can be released.
The IE will check that the necessary procedures are in place to assure that
PACC will not approve any payments without carrying out the necessary approval
process. The EPC Contract provides the IE with the right to spot check any
payments and ascertain whether the payments being made correlate with the
construction progress being reported (and observed based on field inspection).
The IE will also certify PACC's acceptance of mechanical completion after
carrying out the required due diligence review.
TABLE IV-3
PERFORMANCE TEST STANDARDS
Purpose: The Performance Test measures the ability of PACC facilities to
generate cash flow, adequate to service its Senior Debt outstanding,
using the assumptions for average market prices of products and
feedstocks, and average unit prices for utilities contained in the
Base Case for years 2001 through 2011. The Performance Test is
intended to demonstrate that the PACC facilities can operate in
conjunction with the Clark facilities at the forecasted throughput,
yield and operating efficiency without any effects of changes in the
market prices of, or price relationships between, feedstocks and
refined products.
GENERAL TEST PARAMETERS
1. The Performance Test will consist of a Capacity Test and a Reliability
Test to be conducted following Mechanical Completion and Commissioning.
All General Test Parameters will apply to both the Capacity Test and
Reliability Test.
2. The candidate crude oils charged to crude unit AVU-146 will be from the
list in Table IV-4 and actual crude oils as agreed to between PACC,
Foster Wheeler USA Corporation, and the Independent Engineer during all
test runs. The volume mix of crudes shall be approximately 80% from the
heavy category and 20% from the light sour category.
3. All products produced and sold to Clark during the Performance Test
shall meet the specifications set forth in the Process Technical
Specifications set forth in Schedule 1.7 in the Turnkey Specifications.
To the extent the products actually produced deviate from the product
specification, the price shall be
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<PAGE>
adjusted to reflect the values for the processing or sale of such
products by PACC or Clark R&M as approved by the IE.
4. During the Performance Test, the Guaranteed Emission and Effluent Limits
shown in Table IV-5 shall not be exceeded on a ratable basis.
5. During the test period, only one component of spared equipment will be
utilized at any time where redundant components (pumps, compressors,
etc.) are installed. This does not preclude switching among components
of spared equipment during the test period.
6. For purposes of measuring the consumption of each feedstock and utility,
and production of products for calculation of Daily Net Margin, Clark
and PACC will use the measurement systems and equipment that are
utilized for accounting purposes. Meters shall be installed for
measurement of the main feeds, products and utilities between Clark and
PACC. Calibration of such meters will be carried out prior to the
commencement of the Performance Test.
7. Details of the yield accounting approach including measurement
tolerances, analytical procedures, scheduling and reporting during the
Performance Test will be developed between PACC and Foster Wheeler
personnel and the IE before the commencement of the test.
8. PACC and Foster Wheeler may from time to time request modifications to
any of the procedures of the Performance Test. Such modifications will
become effective upon the consent of the IE, which consent shall not be
unreasonably withheld or delayed.
CAPACITY TEST
9. During a continuous 72-hour period, which can be during the Reliability
Test or at another time, the PACC units will be operated at or within
the conditions identified in the process unit performance guarantees
included as attachments to Schedule 5.3 of the EPC Contract. The
capacity test will demonstrate that PACC can achieve design capacity and
efficiency. The summary table below shows some of the major capacity
test parameters.
CAPACITY TEST PARAMETERS
<TABLE>
<CAPTION>
<S> <C> <C>
DELAYED COKER
Charge Rate 80,000 B/D minimum
Total Liquid Product (C5+) yield 58.9 wt% minimum
Coke Drum Cycle 18 Hours maximum
HYDROCRACKER
Charge Rate 35,000 B/D minimum
Total Liquid Product (C5+) yield 111.2 LV% minimum
Hydrogen Makeup 2,152 SCF/BBL Feed maximum
(Chemical)
SULFUR RECOVERY UNIT
Recovered Sulfur 417 LT/Day minimum
Sulfur Recovery Efficiency 99.80% minimum
Incinerator Effluent 250 ppm vol SO2(/1/) maximum
</TABLE>
--------
(1) Dry and 0% excess air basis
9.1 Crude unit AVU-146 will be operated by Clark at a nominal 250,000 bpsd
during the Capacity Test to provide adequate vacuum bottoms feedstock
for the delayed coking unit (DCU 843).
9.2 The delayed coker feedstock will be vacuum resid. The hydrocracker
feedstock will be mixed coker gas oil, light cycle oil, and vacuum gas
oil.
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<PAGE>
RELIABILITY TEST
10. Crude Unit AVU-146 will be operated for 60 consecutive days at a crude
oil charge rate of not less than an average of 245,000 B/D to provide
feedstocks for the Project units. The coker will be operated during the
same period at an average charge rate of not less than 76,340 B/D of
vacuum resid feedstocks. There will be no limitation on the amount of
feedstock processed in Crude Unit AVU-146 and vacuum resid feedstock
sent to the coker subject to physical limitations of the Crude Unit
AVU-146 and safety considerations. The hydrocracker will be operated
during the same period at an average charge rate of not less than
33,250 B/D of mixed coker gas oil, light cycle oil and VGO feedstocks.
11. The Guaranteed Reliability of the Project will be determined by the
achievement of 100% of the Daily Net Margin of $904,500 as described
below. The Project can achieve Substantial Completion by achieving at
least a Daily Net Margin of $859,200 and by Foster Wheeler paying
Reliability Test Buydown Payments according to the schedule in Table
IV-6.
The "Daily Net Margin" generated during a Performance Test is
calculated as follows: (i) the sum of Product Values (as defined
below) for each product produced during the Performance Test minus
the sum of the Feedstock Values (as defined below) minus Variable
Costs (as defined below) divided by (ii) the number of days in such
Performance Test. The Daily Net Margin calculation shown in Table
IV-3 in Schedule 5.3 of the EPC Contract is based on an 80/20
Maya/Arab Light crude slate; any alternate Light Sour crude oil will
affect product yields and utility consumption. It is not anticipated
that changes in the Light Sour crude selection will have a material
impact on the Daily Net Margin. However, any change in crude
selection and the corresponding Daily Net Margin calculation will be
subject to review and agreement by PACC, Foster Wheeler, and the IE.
As used in Daily Net Margin, the following terms have the following
meanings:
"Product Value" means, for any product produced in a Performance Test,
(i) the volume or other measure of such product produced during such
Performance Test multiplied by (ii) the Dollar Value (as defined
below) of such product.
"Feedstock Value" means, for any feedstock consumed in a Performance
Test, (i) the volume or other measure of such feedstock consumed
during such Performance Test multiplied by (ii) the Dollar Value of
such feedstock.
"Dollar Value" of any product or feedstock means the value therefore as
set forth in the Base Case and as listed in Table IV-7 or, if there
is no value set forth in Table IV-7 for such product or feedstock,
as the case may be, a value determined by PACC, with the written
approval of the IE, on a basis consistent with the methodology used
to determine the prices of similar products or feedstocks, as the
case may be, set forth in the Base Case, adjusted to reflect any
differences in quality and transportation costs.
"Variable Costs" means the total of utilities consumed (or produced)
multiplied by the unit price of each utility as specified by the
Services and Supply Agreement assuming base fuel and electricity
costs of $2.307/MMBTU and $.032/KWH, respectively. The consumption
basis for each utility is outlined in the Heavy Oil Project
Guarantee Basis in Schedule 5.3 of the EPC Contract.
B-29
<PAGE>
TABLE IV-4
APPROVED CRUDE OILS
<TABLE>
<CAPTION>
LIGHT SOUR HEAVY
---------- -----
<S> <C>
Arab Light Maya
Basrah Light(*)
Kirkuk(*)
Kuwait(*)
Olmeca(*)
Oriente(*)
Poseidon(*)
Mars(*)
Urals(*)
Vasconia(*)
</TABLE>
(*) These crudes are candidates for use subject to selection of the most likely
crude to be run by PACC and Clark and a process design check to be
performed by Foster Wheeler after such crude is selected by PACC and Clark.
TABLE IV-5
MAXIMUM ALLOWABLE AIR EMISSIONS
<TABLE>
<CAPTION>
TOTAL EMISSIONS T/YR
-------------------------------------
Unit VOC NOX CO S02 PM H2S
---- ----- ------ ------ ------ ----- ----
<S> <C> <C> <C> <C> <C> <C>
HCU 942............................. 32.56 51.16 39.01 8.63 8.95 0.00
DCU 843............................. 34.52 189.22 90.39 30.83 22.35 0.00
SRU 545............................. 5.37 10.51 29.35 387.21 0.66 0.18
Auxillary C.T., Flare, Etc.......... 17.20 0.26 9.21 0.04 0.00 0.00
----- ------ ------ ------ ----- ----
TOTALS.............................. 89.65 251.15 167.96 426.71 31.96 0.18
</TABLE>
Note: The maximum allowable air emissions are subject to revisions based on
final design specifications and operating performance of the PACC-owned
units.
TABLE IV-6
RELIABILITY TEST BUYDOWN PAYMENTS
<TABLE>
<CAPTION>
LIQUIDATED DAMAGES SCHEDULE
---------------------------------------------------------------
Net Daily Margin Buydown
(M$/Day) (MM$)
---------------- -------
<S> <C>
904.50 0.00
899.50 8.28
894.50 16.56
889.50 24.84
884.50 33.11
879.50 41.39
874.50 49.67
869.50 57.95
864.50 66.23
859.50 74.51
859.20 75.00
</TABLE>
Buydown (MM$) = 1.6557 MM$ / 1.0 M$ (Net Daily Margin Impairment).
Note: The Net Daily Margin guarantee basis will be updated to reflect the final
utility volume design data. The Buydown amount of 1.6557 MM$ / 1.0 M$
(Net Daily Margin Impairment) will not change with this update.
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<PAGE>
TABLE IV-7
PRICING--PURVIN & GERTZ 2001-2011 AVERAGE
<TABLE>
<CAPTION>
Pricing--
Purvin & Gertz 2001-
2011 Average
--------------------
<S> <C>
Fuel $2.31 /MMBTU
Reg UL 87 $23.13 $/bbl
Prem UL 93 $25.04 $/bbl
Penhex Sales $18.74 $/bbl
Propylene $22.51 $/bbl
Propane $14.98 $/bbl
N-Butane Sales $16.27 $/bbl
Isobutane $18.29 $/bbl
Butylene $18.58 $/bbl
BB Mix $18.58 $/bbl
Naphtha Purchase $21.63 $/bbl
Kero $23.13 $/bbl
Jet 54 $23.13 $/bbl
LS Dies $22.66 $/bbl
HS Dies $22.00 $/bbl
LS VGO $20.86 $/bbl
HS VGO $19.39 $/bbl
#6 Fuel $11.72 $/bbl
Coke $0.00 $/FOEB
Hydrogen $1.31 /MSCF
Power 3.2 cents/kwH
CW m/u 10 c/gal
Sulfur $41.00 $/LT
Coker Naphtha $19.07 $/bbl
Coker LGO $19.90 $/bbl
Hydrocracker Light
Naphtha $18.11 $/bbl
Hydrocracker Heavy
Naphtha $23.29 $/bbl
Hydrocracker Jet $22.71 $/bbl
Coker VTB $4.05 $/bbl
Vacuum Gas Oil $18.55 $/bbl
FCC Light Cycle
Oil $19.48 $/bbl
650# Steam $3.80 $/mlb
125# Steam $3.59 $/mlb
</TABLE>
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<PAGE>
ENVIRONMENTAL REVIEW
ENVIRONMENTAL PERMITS AND COMPLIANCE
The Refinery is located in Jefferson County, Texas and falls under the
Environmental Protection Agency ("EPA") Region VI, and under Region X of the
Texas Natural Resources Conservation Commission ("TNRCC"). Jefferson County is
classified by the EPA as an ozone non-attainment area. The county was a serious
ozone non-attainment area and was reclassified to a moderate ozone non-
attainment area on June 3, 1996.
The past relationship (under both Gulf and Chevron ownership) as well as the
current relationship between Clark and the federal and state environmental
regulators, is satisfactory. As evidenced by correspondence between Clark and
the agency, good lines of communication are open between Clark and the
regulators and this relationship has facilitated frank and cooperative
discussion on items pertaining to permits and compliance.
The EPA carried out a multimedia (air, water, solid/hazardous waste)
inspection in April 1997 which indicated that Clark was essentially in
compliance. Only two deficiencies were identified; Clark has since corrected
these items to EPA's satisfaction. The most recent TNRCC inspection conducted
in 1998 reported the refinery to be essentially in compliance.
FLEXIBLE AIR PERMIT ALTERATION AND SEPARATION
Clark holds five conventional TNRCC permits and one umbrella or bubble type
flexible air permit. Clark is currently covering most of the Refinery
operations under the flexible air emissions permit (Permit Nos. 6825A and PSD-
TX-49). This air permit is in lieu of the traditional single source permits and
incorporates all of the existing air emissions sources under one umbrella
permit. The flexible air permit establishes 10 individual maximum allowable
emission rates (VOC, NOx, SO2, CO, PM, H2S, HF, NH3, Benzene, and MTBE) and
defined individual limitations (which includes control of fugitive emissions,
opacity, operation of SRUs, visible emissions from heaters and boilers, and
continuous emission monitoring systems, amongst others). The flexible permit
requires Clark to make certain investments beginning in 1994 and ending in
2004, that will ultimately reduce the total air emissions by installing best
available control technology ("BACT") on all grandfathered equipment. In
return, Clark was granted a permit that does not specify emission limits on
each source but instead provides an overall plant limit for each of the ten
pollutants mentioned above. The starting time was determined by
Chevron's/Clark's promise to pursue a flexible permit in 1994. The permit was
approved in 1996. PGI reviewed Clark's 1998 emissions summary which reported
all individual emission caps to be below the maximum allowable limits. Clark is
required to make this demonstration to the TNRCC every quarter, until
continuous emission monitoring equipment is installed that will allow this
demonstration on a real time basis. In view of the reported emissions
documentation and conversations with Clark and the TNRCC, it is apparent that
emissions are routinely within permissible limits.
Clark's 10 year flexible permit capital investment requirements (1994-2004)
includes the addition of low NOx burners, a vapor recovery system at the docks,
fugitive emissions control and monitoring, continuous emissions monitoring
equipment, and process revisions needed to lower the SOx emissions in the FCCU
flue gas. FCCU emissions reductions will be accomplished by lowering the sulfur
content in the FCCU feedstock to 0.3wt%. Clark is targeting to have all items
completed by 2002. The estimated total investment plan is approximately $33
million to achieve all the items.
PGI reviewed documentation provided by Clark that evidences the permits under
the TNRCC jurisdiction that changed ownership in April 1995 after Clark
acquired the Refinery from Chevron USA, Inc. and Chevron Pipe Line Co. In
December 1996, the existing permits were captured under a single permit
referred to as the original Flexible Permit.
The Flexible Permit was amended on August 31, 1998 to allow Clark to
undertake the Project. On March 9, 1999 a request was made by Clark to the
Office of Air Quality of the TNRCC for permit alteration and separation of
Flexible Permit 6825 A. On March 18, 1999, an additional request was made to
TNRCC to
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<PAGE>
once again alter the Flexible Permit and in addition amend Permit 2303 A. These
requests will have the net result of separating PACC from the Flexible Permit
and incorporate the emissions from PACC to Permit 2303 A. This existing permit
covers emissions from four crude oil storage tanks (of which two will be used
as coker feed storage tanks) which are located in the general vicinity of the
PACC site. Permit 2303A will have emissions capped by individual source rather
than the flexible concept. The TNRCC notified Clark on April 29, 1999 that the
amendment to Permit 2303A and the alteration to Permit 6825A had been approved.
Subsequently, on May 12, 1999 Clark requested TNRCC to change the ownership of
Permit 2303 A from Clark to PACC. On May 28, 1999 the TNRCC approved the change
of ownership. This permit gives PACC the right to construct and operate the
Coker Complex. Both permits remain under TNRCC account ID No. JE-0042-B. The
TNRCC considers this reasonable since Port Arthur is functionally one emissions
site.
The revised original Flexible Permit approved by TNRCC requires that
construction of the Upgrade Project begin no later than February 2000. This
condition has already been satisfied since construction has already begun. The
revised Flexible Permit would require a permit modification to continue to
operate the existing coker units once the new coker becomes operational.
In addition to the existing permits, on July 9, 1999, the TNRCC issued to
PACC standby permits (Permit Nos. 6825Z and PSD-TX-49Z) that would replace the
existing Clark Flexible Permit and become effective upon notice by PACC to the
TNRCC. These permits are subject to the same special conditions contained in
the existing Clark permits and would allow PACC to operate the Clark Ancillary
Equipment required to support the Coker Complex operation.
WASTEWATER AND, SOLID AND HAZARDOUS WASTES
The current operation treats all Refinery process wastewater prior to its
discharge into the Neches river via the Refinery joint outfall canal. Chevron,
prior to selling the Refinery to Clark, installed a new wastewater treatment
plant that treats all Refinery wastewater and the wastewater produced at the
Chevron petrochemical plants. The treatment plant is considered a state of the
art facility and incorporates various stages of treatment prior to the
wastewater being discharged. Current wastewater discharge parameters are
routinely below the TNRCC and EPA limits. Clark provided documentation which
shows the Refinery to be in compliance at percentage rates better than the
industry average.
Solid and hazardous wastes are handled, stored, and transported according to
the required RCRA regulations and do evidence any material non-compliance
issues. PGI reviewed a RCRA compliance inspection report done in conjunction
with the multimedia inspection which shows Clark to be essentially in
compliance.
EXISTING SITE CONTAMINATION
The Refinery site was determined to be contaminated prior to Clark's purchase
from Chevron. Black & Veatch, an engineering and environmental consultant, was
retained (November 1994) by Clark to ascertain the pre-existing contamination
of the entire refinery complex. As a condition of the fuels refinery sale by
Chevron to Clark, Chevron retained the environmental liability for the pre-
existing site contamination with exception to those areas classified as
excluded areas which include the areas immediately under and within 100 feet of
the prime fuels operating units (crude unit, FCC, reformer, alky, etc.) The
ground areas that will be leased by PACC have potential soil and underground
water contamination; however, this contamination remains a Clark liability. The
area in which the existing Clark fuels refinery is located represents
approximately 3% of the total Refinery facilities area. The areas occupied by
the tank farm and Chevron's petrochemical plants are also potentially
contaminated and remain under Chevron's responsibility.
Environmental impact studies performed by Clark's environmental consultants,
Black & Veatch, reportedly indicate minimum risk to the surrounding surface and
underground water bodies that are considered as potable drinking water sources.
The underlying geology at the site shows Beaumont clay at an average depth of
30 feet which has a low permeability and tends to impede the downward flow of
groundwater. In PGI's experience it is common for remediation not to be
immediately mandated in circumstances where no potable
B-33
<PAGE>
water sources are endangered. A previous report (November 1994) by Black &
Veatch also indicates that ground water remediation will not be performed for
individual areas of the Refinery, but for the Refinery as a whole.
For those areas outside of Clark's boundaries, Chevron agreed with the
environmental authorities on a site remediation plan, and today, site
remediation in areas under Chevron's responsibility is in progress. The intent
is that the remediation work will continue until the site has reached the
negotiated conditions.
The area that will contain the major PACC units, namely the coker and the
hydrocracker, has potential soil and underground water contamination. Chevron
has agreed to pay Clark an agreed settlement amount, based on forecast cleanup
costs (of any remediation of soil located above the groundwater table), of
approximately $1.4 million in order for Clark to assume this potential
liability. Black & Veatch calculated a cleanup cost estimate of $1 million for
capital costs and $0.8 million for operating costs (based on insitu
stabilization of the soil). Black & Veatch indicated that the settlement amount
would be sufficient for the level of remediation (if remediation were
mandated). As Clark retains all environmental liabilities under the Coker
Complex Ground Lease and Ancillary Equipment Lease for existing site
contamination, PACC is protected against any environmental exposure with
respect to existing conditions.
EFFECT OF PROPOSED GASOLINE SULFUR SPECIFICATIONS
Future gasoline specifications beyond the Complex model have been issued by
the EPA and are referred to as Tier 2. There is currently a debate between the
automobile manufacturers and the refining industry concerning proposed levels
of sulfur in gasoline. The automobile manufacturers association argue that
further improvements to the catalytic converter requires a lower sulfur
gasoline fuel as sulfur is a temporary catalyst poison. The proposed
specifications are an annual average sulfur concentration of 30 parts per
million ("ppm") with a per gallon maximum of 80 ppm. To achieve these
specifications, refiners will be required to make capital expenditures to
construct additional processing units to treat gasoline type streams. New
specifications will likely be decided in 1999 with new requirements going into
effect in 2004.
As the low sulfur specifications are currently in the proposal stage and no
new regulations have been passed at this time, most refiners including Clark do
not have definitive plans to construct the additional equipment necessary to
meet the proposed specifications. With the new PACC hydrocracker and the
existing VGO Hydrotreater (GFU244), Clark will likely only require additional
hydrotreating on the FCCU gasoline and light straight run streams. Clark and
PGI expect this capital expenditure to be no more than $50 million through the
use of idle equipment currently located at the Refinery. Based on Clark's past
commitment to meet the regulations at the Refinery, it is reasonable to expect
that Clark will spend the capital necessary to meet the new proposed
specifications.
MTBE
Recent concerns regarding groundwater contamination by MTBE in California
have prompted a panel of the Environmental Protection Agency to recommend that
Congress enact a ban on MTBE usage. In addition, the governor of California has
signed an executive order regarding the phasing out of MTBE usage over the next
few years. In the past the refinery has produced reformulated gasoline (RFG)
using MTBE produced through a tolling agreement with Huntsman Chemical.
Although the refinery will continue to have the capability to produce RFG
containing MTBE, PACC does not plan to produce MTBE. If a ban on MTBE usage
were to spread throughout the U.S., including Clark's market area, the Refinery
would be prohibited from utilizing MTBE in its gasoline blends. Such an
occurrence would generally affect all refiners more or less equally. PGI
believes that a ban on MTBE usage would not have a material effect on PACC's
operations and cash flow or the competitiveness of the Refinery.
B-34
<PAGE>
COMPETITIVENESS OF REFINERY
Purvin & Gertz utilizes a proprietary methodology to predict the relative net
margin of a refinery of a given configuration compared to other refineries with
different configurations. The index, termed processing power index or PPI, is
based on the conversion capability of the refinery, the hydrogen uptake per
barrel of crude oil processed, and relative size. The PPI is based on seven
different standard index USGC refineries with varying degrees of complexity and
types of crude oil processed. The refinery configurations include both cracking
and coking modes of operations processing sweet and sour crude slates in
various combinations. Calculation of the PPI assumes that the refinery operator
is prudent in all matters regarding operating costs, maintenance practices,
safety and environmental compliance. Based on our analysis, the Refinery will
move into the top five refineries on the US Gulf Coast based on PPI. In
comparison, the Refinery ranks number seventeen per the PPI in the pre-
expansion mode. The graph below illustrates where the refinery is today and
post-project.
[Chart of Figure IV-4 Relative Margin Indicator for 29 USGC Refineries]
B-35
<PAGE>
V. ECONOMIC MODEL
GENERAL
Clark management developed and provided to PGI an economic model to simulate
economics for PACC. PGI examined the model and confirmed the assumptions and
calculations by performing an independent review. PGI considers the economic
model to be an accurate representation of the projected revenues, expenses, and
net cash flows generated by PACC.
The objective of the economic model is to analyze the expected revenue, net
income, and DSCR's. PGI verified the feedstocks consumption, products yields,
operating costs, processing fees, utility/environmental fees, marketing fees,
maintenance turnaround charges, and capital (initial and sustaining)
expenditures based on documents provided by Clark. Our evaluation did not
include verification of financing assumptions, depreciation, reserve fund
requirements, or taxes (corporate, sales, state, municipal, etc.) that were
assumed by Clark and are incorporated into the economic model. Depreciation is
calculated on a 30 year straight line method for book basis and 10 year double
declining balance method for tax purposes. Cash income taxes are assumed to be
at a rate of 35%.
The economic model calculates, on a semi-annual basis, the expected PACC
revenues, project expenses and DSCR beginning November 1, 2000 and ending in
2015. For the purposes of this report the results from the economic model are
reported on a yearly basis. The model incorporates the PGI price forecast
adjusted from a basis of 2% inflation reduced to 1%. A 1% inflation basis
increases conservatism in estimating the debt service coverage ratios. The
basis for the PGI price forecast is discussed in detail in the separate "Crude
Oil and Refined Product Market Forecast".
PACC consists of the delayed coker, hydrocracker, sulfur plant and certain
offsites. PACC is integrated with the existing operations at the Refinery and
its economics are based on the sale of intermediate and finished product
streams at market rates to Clark. In addition to finished and intermediate
product sales, PACC incurs lease and operating fees related to the leasing and
operating costs incurred by the upgrading of PACC intermediate products in PACC
owned and leased units and receives processing fees from Clark for the
processing of Clark intermediate products in the PACC owned and leased units.
Finished product and intermediates pricing are based on widely accepted
market publications such as Platt's with quality discounts or premiums applied
where applicable. All pricing is established at the Refinery gate by applying
appropriate transportation costs and fees to the US Gulf Coast basis.
CAPITALIZATION OF PACC
PACC's capital costs, operating cash deficiencies during construction and
financing expenses (including interest during construction) are to be funded
through a $135 million equity contribution and the issuance of bank term debt
($325 million) and capital markets debt ($255 million). The bank term debt has
a final maturity of 7.5 and 8 years with a prepayment mechanism allowing for
75% of the excess cash flow to prepay outstanding bank term debt. The remaining
25% of free cash flow is available to fund the debt service reserve account and
thereafter for dividends subject to certain restrictions. The capital markets
debt will consist of $255 million with a term of 9.3 years and an average life
of approximately 7.0 years. Semi-annual interest payments are capitalized
through the construction period to March 1, 2001 with cash interest payments
beginning in July 2001 and scheduled principal amortization beginning in
January 2002.
A $75 million working capital facility will be established to provide letters
of credit for non-Maya crude oil purchases and to provide "compensating
collateral" under the PMI Contract. A $150 million Guaranty Insurance Policy
will be issued by Winterthur International Insurance Company Limited, an "AA-"
rated insurance company, in lieu of a traditional working capital facility for
letters of credit for all PACC Maya crude oil purchases. Premiums are paid
annually in advance beginning at financial close.
B-36
<PAGE>
In lieu of an initial debt service reserve account being funded by PACC
(equal to six months of interest and principal amortization payments), a Debt
Service Reserve Insurance Guarantee ("DSRIG") is to be provided by Winterthur.
Premiums on the DSRIG will be paid annually in advance beginning at financial
close. The DSRIG is reduced over time and replaced with a debt service reserve
account that will be funded initially with the residual excess cash flow
generated by PACC after prepayment of bank debt. New PACC equity of $135
million (19% of total sources of funds) is to be contributed by Blackstone
Capital Partners III L.P. (90%) and Occidental Petroleum (10%).
A PMI surplus reserve account ("PMI Account") will be established to retain
funds in an amount equal to the net quarterly surpluses that will have accrued
pursuant to the Differential formula up to a maximum amount of $75 million,
which will be automatically reduced to $50 million upon repayment in full of
all bank term debt. This reserve will be adequate to provide liquidity to PACC
in case of reduced cash flows because of a delay in discounting Maya until all
prior surpluses have been fully used. The combination of a fully-funded PMI
Account and the debt service reserve account will provide PACC with liquidity
up to 1.25 years of debt service.
At financial close, PACC, with PGI's certification, will reimburse Clark for
all PACC related capital outlays incurred since Upgrade Project inception (a
projected total of approximately $139 million though July 31, 1999). PACC will
also pay Clark $2.2 million for transfer of value items including the PMI
Contract and other items.
REVENUES
PACC generates revenues from processing approximately 200,000 bpsd of crude
oil (80% Maya and 20% light sour), selling products to Clark (mainly LPG,
diesel, intermediates, coke, and sulfur) and receiving fees from Clark for
processing Clark feedstocks (approximately 50,000 bpsd of crude oil). The
salable products are based on the material balance yields used as the basis in
the economic model which incorporates yields guaranteed by Foster Wheeler as
part of the Performance Test. The prices received for the products sold are
based on the PGI market price forecast. As indicated in prior sections of this
report, the prices are adjusted from market prices for quality and freight for
price realization at the refinery gate.
Since feedstocks and products purchased and sold by PACC are handled by
Clark, a per barrel fee component is charged to PACC. The rates used in the
financial model and listed in the table below are representative of typical
handling fees charged by third-party entities.
TABLE V-1
HANDLING FEES
<TABLE>
<S> <C>
Finished Product.................. $0.021/bbl
LPG's & Intermediates*............ $0.042/bbl
Crude............................. $0.030/bbl
Coke.............................. $0.010/bbl
</TABLE>
--------
* Fee will only be charged if
intermediate is sold to a 3rd party
Sales to a 3rd party will occur during a
turnaround or during abnormal operation
B-37
<PAGE>
FEEDSTOCKS TO PACC
Feedstocks purchased by PACC consist of Maya crude oil purchased under the
PMI Contract from PMI and a light sour crude oil purchased on the spot market.
To allow processing of the Maya crude oil at the Refinery, a volume of light
sour crude oil (the model assumes Arab Light) equal to approximately 20% by
volume of the total crude oil processed is required. The crude oil will be fed
to the crude/vacuum unit that is being leased by PACC and PACC will pay a lease
fee to Clark for utilizing 100% of the crude unit. In addition to crude oil
purchased by PACC, Clark has the right to process additional crude oil
purchased by them through crude/vacuum units. In such case, a processing fee
will be paid by Clark to PACC for such processing. Products from the
crude/vacuum unit will be split according to the respective percentages of PACC
and Clark crude oil processed (approximately 80% PACC and 20% Clark). In
addition to the crude oil liquid feedstocks, PACC will purchase hydrogen needed
for the hydrocracker from APCI at a price of 1.8648 times fuel value plus a
fixed fee.
Residue from the vacuum unit will be fed to the new delayed coker. As
mentioned, the proportion of residue fed to the coker is equal to the
percentage of PACC crude processed through the crude/vacuum units. Light
products from the delayed coker will be sold back to Clark at market reference
prices.
Coker heavy gas oil will be fed to the hydrocracker along with light cycle
oil from Clark and VGO from the crude/vacuum unit. Products from the
hydrocracker are sold to Clark at market reference prices.
The sulfur plant will process acid gas only from PACC units and have the
capability to process minor amounts of acid gas from the Clark units, if
necessary.
YIELDS FROM PACC
Product yields and quality estimates from PACC have been made by Clark and
Foster Wheeler. The yields are based on information provided by each of the
process licensors. Coker yields are based on Foster Wheeler's extensive
experience with designing and constructing delayed cokers worldwide. The
hydrocracker yields are based on pilot plant testing performed by Chevron on
feedstock similar to that used in PACC. The assumed product yields and
qualities are reasonable and consistent with expectations for such refinery
units. The Base Case projections are those yields which have been guaranteed by
Foster Wheeler as part of the performance test in the EPC contract. These
yields represent 97% of design yields for the coker and 95% of design yields
for the hydrocracker.
Beginning on December 15, 2000, revenues for PACC are initiated with a 80%
onstream operation assumed for a 45 day period. Following the 45 day start-up
period, the remainder of 2001 is assumed to operate at 95% of normal operating
rates. Normal operation is assumed to begin in 2002.
OPERATING COSTS AND SUSTAINING CAPITAL
Clark has prepared detailed estimates of the variable and fixed operating
costs for the PACC units (coker, hydrocracker, sulfur plant). These estimates
are the basis of the Services and Supply Agreement. Variable costs are those
items that vary with throughput which include fuel, electricity, steam, other
utilities, and chemicals consumed in daily operations. PACC's variable cost
estimate has been developed from detailed utilities estimates prepared by
Foster Wheeler and associated sub-contractors. The current estimate for
variable costs, which are predominantly expenditures for fuel and electricity,
is approximately $0.38/BBL or about $28 million per year. Variable costs are
priced as follows:
. Fuel (total consumed)--Calculated based on the fuel gas price forecast.
. Steam (included in the fuel expense line item)--Based on the incremental
cost of steam from APCI with prices indexed to the fuel gas price
forecast.
. Electricity--Based on the incremental cost of electricity from APCI and
other third party providers with price indexed to the fuel gas price
forecast.
. Other--Includes water, nitrogen, and other miscellaneous services.
B-38
<PAGE>
Fixed costs are expenditures that are unaffected by varying throughput and
include items like administration, process labor, maintenance, taxes,
insurance, and overheads. Clark also includes catalyst and chemicals in fixed
costs to coincide with their accounting conventions. Catalyst and chemicals are
assumed to be purchased as needed and are amortized over the useful life.
Initial supplies of catalyst and chemicals are included as start up costs.
Labor expenses include both operations and maintenance and are estimated to be
$10 million per year. In 2001, expenses include an additional $1.5 million for
new unit troubleshooting. Expenses are inflated at 2% per year. Details of
direct and indirect labor are as follows:
TABLE V-2
LABOR EXPENSES
<TABLE>
<CAPTION>
Million $ Per Year
------------------------
PACC Clark R&M Total
Employees Employees Employees Base OT Benefits Total
--------- --------- --------- ---- ---- -------- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Coker................... 27 15 42 $2.1 $0.3 $1.0 $3.4
Hydrocracker............ 9 -- 9 0.5 0.1 0.2 0.8
Acct/Admin.............. 1 2 3 0.1 -- 0.1 0.2
Sulfur Unit............. 6 -- 6 0.3 -- 0.1 0.4
SWS/Amine Unit.......... 4 -- 4 0.2 -- 0.1 0.3
--- --- --- ---- ---- ---- ----
Subtotal.............. 47 17 64 $3.2 $0.4 $1.5 $5.1
Maintenance............. 36 36 $1.8 $0.3 $0.8 $2.9
Unit/Maintenance
Supervision
Operations.............. -- 12 12 $0.8 $-- $0.3 $1.1
Maintenance............. -- 4 4 0.3 -- 0.1 0.4
--- --- --- ---- ---- ---- ----
Subtotal.............. -- 16 16 $1.1 $-- $0.4 $1.5
Clerical................ -- 6 6 $0.2 $-- $0.1 $0.3
--- --- --- ---- ---- ---- ----
Totals................ 47 75 122 $6.3 $0.7 $2.8 $9.8
</TABLE>
Repairs and maintenance includes both materials and contract labor. The
repairs and maintenance costs of the new coker, hydrocracker, and sulfur plant
are based on industry averages for similar units and are estimated to be
approximately $5 million after the first year of operation inflated at 2%
thereafter. In year 2001, an additional expense of $2.5 million is assumed for
troubleshooting. Total repairs and maintenance as an average percentage of unit
replacement cost over 15 years including maintenance labor, materials, contract
labor, turnaround and mandatory capital are 4.5% for the PACC units and off-
sites. Major turnarounds of the coker, hydrocracker, and crude unit are assumed
to occur in years 2004, 2008 and every four years thereafter. Crude unit heater
de-coke and hydrocracker catalyst change are assumed to occur during interim
outages in years 2002, 2006, and 2010.
B-39
<PAGE>
Environmental costs are based on historical Refinery environmental costs of
$0.2 million per year associated with operating the existing cokers plus $0.6
million per year for waste services, inflated at 2% per year. An incremental
insurance premium of $2 million per year for business interruption and process
units is included based on Marsh & McLennan estimates. The base tax rate
included is 3% of the assessed property value less assigned abatement and
environmental exemptions for pollution control equipment.
General and administrative (G&A) expenses are estimated at $700,000 per year.
This includes $200,000 for accounting and optimization activities to be
conducted by Clark, and $500,000 for corporate activities such as tax services,
information services, legal fees, insurance administration, bondholder
relations and SEC filing requirements. These expenses are adjusted for
inflation at 2% annually. The support services/other category includes support
services as detailed below:
TABLE V-3
SUPPORT SERVICES/OTHER
<TABLE>
<CAPTION>
Million $ Per Year
-------------------
Total
Employees Base Benefits Total
--------- ---- -------- -----
<S> <C> <C> <C> <C>
Site Management................................... 1 $0.1 $ -- $0.1
Technical......................................... 4 0.3 0.1 0.4
Laboratory........................................ 8 0.4 0.2 0.6
Accounting........................................ 3 0.1 0.1 0.2
EH&S.............................................. 3 0.2 0.1 0.3
--- ---- ---- ----
19 $1.1 $0.5 $1.6
EMS............................................... $0.1 $ -- $0.1
Security.......................................... 0.3 -- 0.3
General........................................... 0.6 -- 0.6
G&A--Corporate Offices............................ 0.7 -- 0.7
Misc. Supplies.................................... 0.1 -- 0.1
Other............................................. 1.4 -- 1.4
---- ---- ----
$3.2 $ -- $3.2
----
Total Other Expenses.............................. $4.8
</TABLE>
B-40
<PAGE>
A sustaining capital component averaging approximately $5 million per year
has also been included for capital replacements and other required
expenditures. The sustaining capital outlays are projected to be lower than
average in the early years when the equipment is new and higher than average in
the later years. The operating and maintenance cost and sustaining capital
projections set forth in the economic projections are reasonable and sufficient
for the operation and maintenance of PACC. Total operating costs are summarized
in the table below:
TABLE V-4
OPERATING COSTS
<TABLE>
<CAPTION>
Variable ($/bbl) 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---------------- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Fuel.................... 0.23 0.22 0.22 0.23 0.23 0.23 0.23 0.24 0.24 0.26
Electricity............. 0.15 0.17 0.16 0.18 0.16 0.17 0.17 0.19 0.17 0.19
Total Variable expenses. 0.37 0.39 0.38 0.41 0.39 0.40 0.40 0.42 0.40 0.45
<CAPTION>
Fixed (million $/year)
- ----------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Operating labor......... 11.26 9.96 10.16 10.36 10.57 10.78 11.00 11.22 11.44 11.67
Cat / Chemicals......... 4.44 4.26 4.26 4.49 4.68 4.87 5.07 5.27 5.48 5.70
Repairs & Maintenance... 7.27 4.86 4.96 5.06 5.16 5.26 5.37 5.47 5.58 5.70
Environmental........... 0.77 0.78 0.80 0.82 0.83 0.85 0.87 0.88 0.90 0.92
Taxes and Insurance..... 5.91 9.75 9.89 10.10 11.15 12.37 13.97 14.54 14.95 16.80
Support Services/Other.. 4.69 4.78 4.88 4.98 5.07 5.18 5.28 5.39 5.49 5.60
Total Fixed expenses
(million $/year)....... 34.34 34.40 34.94 35.81 37.46 39.30 41.54 42.77 43.85 46.39
</TABLE>
PROCESSING/LEASE FEES
Under the Ancillary Equipment Lease, PACC pays a lease fee to Clark for use
of 100% of the crude/vacuum unit, and distillate, kerosene, and naphtha
hydrotreaters. In addition, under the Ancillary Equipment Lease, PACC pays
operating fees to Clark for all units, which include fees for turnaround and
sustaining capital accrual, fuel and fixed operating cost. 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. These
fees encompass both a fixed and variable cost component as well as a capital
recovery component. The capital recovery component in the lease fee assumes a
25% after tax rate of return for the coker and hydrocracker, 15% after tax rate
of return for other new capital investment, and 3% after tax rate of return for
use of existing assets. Under the Services and Supply Agreement, processing
fees are paid to PACC by Clark to process Clark's portion of the vacuum residue
in the delayed coker. In addition, Clark pays PACC a processing fee to process
LCO, coker HGO, and crude still VGO through the hydrocracker. Clark also pays
for use of a portion of the crude/vacuum unit and hydrotreaters.
B-41
<PAGE>
The table below summarizes the processing, operating and lease fees for the
Upgrade Project.
TABLE V-5
PROCESSING/LEASE FEES (million $ per year)
<TABLE>
<CAPTION>
PACC Processing Fee Revenue 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- --------------------------- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Coker................... 25.6 26.3 26.8 27.2 27.9 28.4 28.9 29.3 30.0 30.6
Hydrocracker and Sulfur
Plant.................. 28.5 29.3 29.9 30.4 31.1 31.6 32.3 32.7 33.5 34.1
Crude Unit.............. 10.8 11.3 11.6 11.5 12.0 12.1 12.3 12.3 12.8 12.9
Hydrotreaters........... 4.7 5.0 5.1 5.0 5.2 5.3 5.4 5.4 5.6 5.7
Total Processing Fee
Revenue................ 69.7 72.0 73.4 74.1 76.1 77.4 78.9 79.7 81.9 83.3
<CAPTION>
PACC Lease Fee Expenses
- -----------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Crude Unit.............. (25.5) (26.0) (26.6) (27.2) (27.6) (28.2) (28.7) (29.4) (29.9) (30.5)
Distillate Hydrotreater. (2.3) (2.3) (2.4) (2.4) (2.5) (2.5) (2.6) (2.6) (2.7) (2.7)
Jet Hydrotreater........ (2.0) (2.0) (2.1) (2.1) (2.1) (2.2) (2.2) (2.3) (2.3) (2.4)
Naphtha Hydrotreater.... (1.8) (1.8) (1.8) (1.9) (1.9) (2.0) (2.0) (2.0) (2.1) (2.1)
Total Lease Fee Expense. (31.6) (32.2) (32.8) (33.6) (34.2) (34.8) (35.5) (36.4) (37.0) (37.7)
<CAPTION>
PACC Operating Fee Expenses
- ---------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Crude Unit.............. (35.1) (36.6) (38.0) (37.3) (39.2) (39.1) (40.2) (39.4) (41.4) (41.7)
Distillate Hydrotreater. (9.3) (9.9) (10.0) (9.9) (10.3) (10.5) (10.6) (10.5) (11.0) (11.2)
Jet Hydrotreater........ (6.0) (6.4) (6.5) (6.4) (6.7) (6.8) (6.9) (6.8) (7.1) (7.2)
Naphtha Hydrotreater.... (5.5) (5.8) (5.9) (5.8) (6.1) (6.2) (6.3) (6.2) (6.5) (6.6)
Total Operating Fee
Expense................ (55.8) (58.7) (60.5) (59.4) (62.3) (62.6) (64.0) (62.9) (66.0) (66.7)
Total Lease & Operating
Fee Expense............ (87.4) (90.9) (93.3) (93.0) (96.5) (97.4) (99.5) (99.3) (103.0) (104.4)
</TABLE>
PGI has reviewed these fees and believes that they are structured on an arms
length basis and could be achieved under contract with a third party and
represent fair market terms.
AMORTIZATION
Turnaround expenses for the various units are amortized over the life of the
turnaround. The expenses are based on industry averages for units of similar
size. Turnaround expenses for the crude unit and hydrotreater are paid by Clark
and included as part of the operating fees incurred by PACC. Cash turnaround
costs will be accumulated annually through a restricted cash account
specifically for turnaround expenditures. The turnaround amortization period
for all major PACC units is 4 years. Financing fees are amortized based on the
final maturity of the various issues and amortization of royalty payments are
based on the depreciable life of the asset.
CONSTRUCTION MANAGEMENT SERVICES
Construction management services will be provided by Clark prior to Final
Completion under the SSA at a fixed cost of $7 million. These costs will be
paid by PACC over a 3 year period following startup of the PACC Project
(approximately $2.7 million per year including interest).
B-42
<PAGE>
DEBT SERVICE COVERAGE RATIOS
DSCRs are calculated by taking after tax cash flows (defined as EBITDA less
sustaining capital expenditures less amortized turnaround expenses less cash
taxes) as a ratio to scheduled principal amortization and cash interest
payments. In addition to the Base Case, a variety of other cases were examined
to test the robustness of PACC economics and the availability of cash flow to
service the outstanding debt. These cases and results are described in the
table below:
TABLE V-6
DESCRIPTION AND RESULTS OF CASES
<TABLE>
<CAPTION>
Average Minimum
Case Description DSCR DSCR
-------------------------------- ---------------------------- ------- -------
<S> <C> <C> <C>
Base Case....................... Base financial model with 2.4 2.0
PGI pricing forecast
Base Case w/o PMI Contract...... 2.4 1.9
Base financial model with
PGI pricing forecast but
assumed that the PMI
Contract was not in place
Backcast Case................... Used 1989-1998 historical 2.0 0.9*
pricing
Backcast Case w/o PMI Contract.. 2.0 0.9*
Used 1989-1998 historical
pricing but assumed that the
PMI Contract was not in
place
Downside Case................... Assumed 1996 pricing during 1.9 1.1
the first three years of
full operations followed by
PGI forecast
Reduced Utilization Case........ On-stream utilization 2.2 1.9
reduced by 5% to 95% of Base
Case utilization
Reduced Coker Yield Case........ Decreased coker design 2.3 1.9
yields by 5%
Reduced Hydrocracker
Conversion Case................. Decreased hydrocracker VGO 2.4 2.0
conversion by 10%
Operating Cost 2.2 1.9
Increase Case................... Increased fixed and variable
cost
by 20%
</TABLE>
- --------
* In 2007, the Backcast Case cash flow available for debt service shortfall
amounts to approximately $3.0 million. The shortfall is primarily a result
of prior year surpluses which have not been fully used so that discounts
are not allowed under the PMI Contract. This scenario is mitigated by the
PMI Account. Consequently, in this year, PACC will have a fully funded PMI
Account of $50 million, debt service reserve account of $37 million and
over $100 million of additional cash available for debt service. In the
Backcast Cast without PMI Contract, cash flow available for debt service
shortfall amounts to approximately $5.0 million, with a debt service
reserve account of $37 million and over $100 million of additional cash
available for debt service.
B-43
<PAGE>
The results demonstrate that PACC is able to service its debt obligations
under a variety of scenarios. Detailed tables supporting these cases are shown
in Tables V-9 to V-26.
Each case is discussed in more detail below.
BASE CASE
The Base Case has been defined in preceding paragraphs. PGI believes that the
Base Case projections are achievable and that they are a reasonable
representation of the expected performance of PACC. The Base Case provides a
minimum after tax DSCR of 2.0 and an average after tax DSCR of 2.4.
SENSITIVITIES
Due to the uncertainties necessarily inherent in relying on assumptions and
projections, it should be anticipated that certain circumstances and events may
differ from those assumed and described herein and that such circumstances may
affect the results of our Base Case. In order to demonstrate the impact of
certain events on the Base Case economics, a number of sensitivity cases were
tested. It should be noted that other cases than those described below might be
considered. The sensitivities recommended are not presented in any particular
order with regard to the likelihood of any case actually occurring. In
addition, no assurance can be given that all relevant sensitivities are
addressed, that the level of each sensitivity is the appropriate level for
testing, or that only one (rather than a combination of more than one) of such
variations or sensitivities could impact PACC in the future.
Base Case--No PMI Contract
This sensitivity involves the loss of the PMI Contract. In the Base Case,
PACC receives a discount on Maya purchases during the first two years of
operation followed by a surplus situation whereby PACC pays a premium on Maya
purchases until the aggregate of the shortfalls is offset. Without the PMI
Contract in effect, the average DSCR is 2.4 compared to the Base Case of 2.4,
with the minimum DSCR being 1.9. The results reflect the fact that the basic
intent of the PMI Contract is not to provide a subsidy for oil purchases.
Backcast Case
A Backcast Case was generated using 1989-1998 historic pricing to correspond
to the volume projections for 2001 to 2010. The intent of the Backcast Case is
to illustrate historic cyclicality of the petroleum market. On-stream
utilization and yields were kept the same as the Base Case. The PMI Contract is
assumed to be in place for the Backcast Case. The average DSCR is determined to
be 2.0 with a minimum DSCR of almost 1.0 in 2007 (a 1995 pricing environment).
In 2007, the cash flow shortfall amounts to only $3.0 million and is a result
of the absence of discounts due to prior year surpluses under the PMI Contract.
As discussed, to mitigate this risk, the PMI Account is fully funded ($50
million) to cover this shortfall in addition to the $37 million balance in the
debt service reserve account.
Backcast Case--No PMI Contract
An additional Backcast Case was generated which assumes the PMI Contract is
not in place. This case results in an average DSCR of 2.0 with a minimum DSCR
of almost 1.0. Again, the results do not materially change from the Backcast
Case with the PMI Contract for the same reasons explained above. The shortfall
of available cash flow for debt service in 2007 amounts to $5.0 million. This
shortfall would be covered by the debt service reserve account.
Downside Case
A downside case was also developed that incorporates 1996 prices during the
period 2000-2003 with PGI's forecast used thereafter. This scenario tests the
impact of an extended period of weak coker economics.
B-44
<PAGE>
In the past ten years of history, it was found that the worst year for coker
performance in conjunction with the coker gross margin stabilization under the
PMI Contract occurred in 1996; hence, the use of 1996 pricing during the first
three full years of operation followed by the Base Case assumptions. PGI
believes that a three year period of depressed coker economics is highly
unlikely and would likely self-correct as a result of a decline in addition of
new coker projects. The average after-tax DSCR was determined to be 1.9 with a
minimum DSCR of 1.1. During the first three years the DSCR were 1.5, 1.1 and
1.2.
Reduced Utilization Case
The effect of a change in utilization or on-stream factor was tested by
reducing the overall on-stream factor to 95% of the Base Case which effectively
is 90% of design rates in bpsd. A reduction in utilization could occur as a
result of under-design of key pieces of equipment or mechanical reliability
issues. This change in utilization impacts PACC's operating cash flow by only
$14.1 million in 2003 (or about 6%) with a reduction in average DSCR from 2.4
to 2.2.
Reduced Coker Yield and Reduced Hydrocracker Conversion Cases
There is the possibility of achieving less than the expected product yields
from the delayed coker and the hydrocracker units. Although PACC utilizes well-
proven technology, there is always risk associated with the start-up of newly
constructed units. A key performance indicator of delayed coker operation is
the percentage of feedstock that is converted to lighter more valuable liquid
products. Along the same line, a key performance indicator of hydrocrackers is
the conversion of VGO feedstock. Conversion not only impacts the amount of
light, more valuable fuels products that are produced, but also adversely
affects the VGO balance resulting in the sale of excess VGO. Cases were
evaluated to analyze a reduction of 5% of the delayed coker liquid volume yield
and a 10% reduction in hydrocracker conversion resulting in average DSCRs of
2.3 and 2.4, respectively.
Operating Cost Increase Case
Variable and fixed operating costs were both increased by 20% to simulate
lower efficiencies and higher than expected labor or maintenance costs. A 20%
increase in operating costs results in an average and minimum DSCR of 2.2 and
1.9.
An additional sensitivity was performed which assumes that PACC operates
without the rest of the Clark facility in operation. This case is discussed in
the next section.
STAND-ALONE CASE
To demonstrate the robustness of the economics of the PACC, PGI developed an
alternative case scenario under which PACC continues its operations while the
rest of the Refinery not leased or used by PACC in the Base Case discontinues
its operations. PACC would continue to have access to all leased and owned
units. It is assumed a third-party would replace Clark as operator. In a stand-
alone operation, PACC will need to arrange for crude purchases and logistics as
well as product sales and logistics. These functions are assumed to be
contracted to third parties for fees similar in magnitude to those assumed in
the Base Case.
CONFIGURATION
The stand-alone operation scenario assumes that the PMI Contract remains in
effect and that the crude unit continues to process 250,000 bpsd of crude oil.
The delayed coker, hydrocracker, sulfur plant, the crude/vacuum unit and the
sat gas plant, as well as the distillate hydrotreaters (GFU 242 and GFU 243),
will be required to process crude oil. In addition, boilers, tankage, transfer
piping, control houses, laboratory, and miscellaneous equipment and buildings
are all assumed to be available to PACC. The crude and distillate hydrotreating
units are assumed to be available to PACC for the lease fees stated in the
Processing/Lease Fees section previously described.
B-45
<PAGE>
Relatively minor modifications to piping would be needed to implement the
stand-alone case. In addition, modifications will be required at the PACC
sulfur plant to handle the additional sulfur load which entails the use of
oxygen enrichment. Additional variable costs are included in the cash flow
model to account for this oxygen usage. PGI believes that the cost to modify
the Refinery and PACC to support a stand-alone operation would not exceed $5
million, nor take longer than 3 months to implement.
PRODUCTS
In the stand-alone operation, the catalytic reformer, FCCU, and the
alkylation unit will not be operated. As a result, the only specification
products produced will be low sulfur diesel fuel and kerosene. All other
product streams from the operating units are intermediate products,
specifically light naphtha or penhex, reformer feed, and low and high sulfur
VGO and which are sold to the spot market.
PRICING
Stand-alone product pricing is adjusted to reflect discounts or premiums due
to quality, transportation fees, and market discounts. The quality and
transportation discounts are applied throughout the pricing period, however,
market discounts are applied only for the first 3 years.
Naphtha pricing depends primarily on whether the naphtha is light or heavy,
whether it has been stabilized, and its naphthene and aromatic ("N+A") content.
Heavy naphtha and higher N+A naphtha command a higher price versus light
naphtha and low N+A product. Premiums and discounts have been applied as
appropriate to naphtha produced in the crude, hydrocracker, and coker units.
Light naphtha, for example, is valued to the olefins cracker market and/or
gasoline blending and is priced at USGC natural gasoline less the required
discount.
The effect of introducing 40,000 bpsd of poor quality unstabilized
Hydrocracker and Coker naphtha into the reformer naphtha market will result in
discounts in addition to the quality discount as supply will outweigh demand.
In 1998, the imports of reformer naphtha into the U.S. Gulf Coast were about
60,000 bpsd which represents the incremental supply to meet the demand for
reformer feed. Introducing the incremental supply of naphtha into the market
will impact the price of naphtha for several years until an equilibrium
supply/demand balance is achieved. To account for the market impact of the
introduction of additional reformer type naphtha on the market, a 5 c/gallon
discount was applied for the first three years of stand-alone operation.
Furthermore, typical transportation charges have been applied. Price discounts
for the various naphthas produced are shown in Table V-7.
Low sulfur VGO was priced using PGI's long term forecast, with no additional
discounts, applied as shown in Table V-7. A 2 c/gallon discount was applied to
the PGI forecast of HS VGO to compensate for the poor quality and an additional
3 c/gallon was applied to cover the market impact of introducing 50,000 bpsd
into the market. The market discount was assumed only for the first three years
of stand-alone operation and is based on historical trends related to quality
and volume discounts. As with naphtha, all the VGO pricing is adjusted for a
transportation fee.
B-46
<PAGE>
In addition to naphtha and VGO, coke and sulfur pricing have been adjusted
for quality and transportation as shown in Table V-7.
TABLE V-7
STAND-ALONE CASE--PRODUCT PRICING
<TABLE>
<S> <C>
Crude Stabilized Naphtha USGC Natural Gasoline - 2 c/gal processing fee - 1.5 c/gal transportation
Hydrocracker Stabilized
Naphtha USGC Natural Gasoline - 2 c/gal processing fee - 1.5 c/gal transportation
Hydro. Crude / Coker
Naphtha USGC Naphtha - 2.5 c/gal quality - 5 c/gal ( 3 years) market - 1c/gal trans.
Hydrocracker Heavy
Naphtha USGC Naphtha + 2 c/gal - 1 c/gal transportation
LS VGO USGC VGO - 1c/gal transportation
HS VGO USGC HS VGO - 2 c/gal quality - 3 c/gal ( 3 years) market - 1 c/gal trans.
Coke (FOEB) USGC Fuel Grade Coke - quality adjustment - transportation
Sulfur ($/ton) USGC Market - transportation
</TABLE>
OPERATING COSTS
Fixed and variable operating costs were held consistent with the Base Case.
These costs, which are market-based and replicate what a third-party could
provide, include all fuel and power, labor, maintenance, turnaround,
environmental, and associated costs required to operate PACC. All lease and
operating fees paid by PACC were also held consistent with the Base Case. All
processing fees formerly received from Clark were assumed to be zero.
DSCR
Both a forecast and backcast case were developed for the stand-alone case.
These cases use the same pricing basis as discussed previously in the Base Case
and Backcast Case but with the adjustment for the naphtha and vacuum gas oil
prices. The CSA is assumed to be in effect. Interest expense and principal
amortization were held consistent with the Base Case financial model. The DSCR
for these cases are as follows:
TABLE V-8
STAND-ALONE CASE
<TABLE>
<CAPTION>
DSCR
---------------
Average Minimum
------- -------
<S> <C> <C>
Forecast.................... 1.9 1.1
Backcast.................... 1.7 0.7
</TABLE>
In the forecast case, the minimum DSCR of 1.1 occurs in 2004 which includes a
turnaround. Even though the backcast has a minimum DSCR of 0.7 in one year, the
PMI Account was fully funded at $50 million and would be able to cover the
shortfall of $17.4 million. In the backcast case, the 0.7 coverage coincided
with a period of poor coker margins in 1995 and a net aggregate surplus under
the PMI Contract, thereby not allowing for Maya discounts. This demonstrates
the benefit of establishing the PMI Account. The supporting tables for the
stand-alone case are shown in Tables V-27 and V-28.
PGI is of the opinion that the stand-alone scenario will be an extremely
remote possibility since the Refinery will be one of the most competitive
refineries in the USGC after startup of the Upgrade Project. Even in a
bankruptcy proceeding against Clark, it would be more beneficial to continue to
operate the Refinery, since Clark would continue to receive the lease and
operating fees.
B-47
<PAGE>
TABLE V-9
PORT ARTHUR COKER COMPANY L.P.
BASE CASE
CHARGES AND YIELDS
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
Products--Volume (bpd in
thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
DISTILLATES
LS Diesel................... 38.3 40.6 40.8 38.5 40.8 40.6 40.8 38.5
Jet Fuel.................... 25.2 26.3 26.8 25.3 26.8 26.3 26.8 25.3
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Distillates....... 63.4 66.9 67.6 63.8 67.6 66.9 67.6 63.8
LPG
Propane..................... 1.1 1.1 1.2 1.1 1.2 1.1 1.2 1.1
Isobutane................... 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Normal Butane............... 2.1 2.2 2.2 2.1 2.2 2.2 2.2 2.1
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--LPG............... 3.5 3.7 3.8 3.6 3.8 3.7 3.8 3.6
UNFINISHED
Coker Propane Propylene Mix. 2.1 2.2 2.2 2.1 2.2 2.2 2.2 2.1
Coker Butane Butylene Mix... 1.5 1.6 1.6 1.5 1.6 1.6 1.6 1.5
Penhex...................... 9.1 9.5 9.7 9.1 9.7 9.5 9.7 9.1
Virgin Diesel............... 7.3 7.0 7.8 7.4 7.8 7.0 7.8 7.4
Naphtha--Sour............... 34.5 36.1 36.8 34.7 36.8 36.1 36.8 34.7
Heavy Naphtha............... 3.7 3.8 4.0 3.7 4.0 3.8 4.0 3.7
ULS VGO..................... 10.1 10.6 10.8 10.2 10.8 10.6 10.8 10.2
VGO......................... 43.6 45.8 46.5 43.9 46.5 45.8 46.5 43.9
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Unfinished........ 112.0 116.5 119.4 112.5 119.4 116.5 119.4 112.5
OTHER PRODUCTS
Sulfur...................... 1.2 1.3 1.3 1.2 1.3 1.3 1.3 1.2
Coke........................ 17.9 18.8 19.1 18.0 19.1 18.8 19.1 18.0
Produced Fuel............... 4.3 4.3 4.4 4.2 4.4 4.3 4.4 4.2
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other Products.... 23.5 24.4 24.9 23.4 24.9 24.4 24.9 23.5
----- ----- ----- ----- ----- ----- ----- -----
TOTAL PRODUCTS............... 202.4 211.5 215.7 203.3 215.7 211.5 215.7 203.3
Chargestocks--Volume (bpd in
thousands)
CRUDE
Arab Lt..................... 37.7 39.5 40.2 37.9 40.2 39.5 40.2 37.9
Maya........................ 150.9 157.8 160.9 151.7 160.9 157.8 160.9 151.7
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Crude............. 188.6 197.3 201.1 189.6 201.1 197.3 201.1 189.6
OTHER CHARGESTOCKS
GFU Feed.................... 1.5 1.6 1.6 1.5 1.6 1.6 1.6 1.5
Hydrogen.................... 3.4 3.5 3.6 3.4 3.6 3.5 3.6 3.4
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other
Chargestocks............... 4.9 5.1 5.2 4.9 5.2 5.1 5.2 4.9
----- ----- ----- ----- ----- ----- ----- -----
TOTAL CHARGESTOCKS........... 193.5 202.4 206.3 194.5 206.3 202.4 206.3 194.5
</TABLE>
B-48
<PAGE>
TABLE V-10
PORT ARTHUR COKER COMPANY L.P.
BASE CASE
PRICE FORECAST
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
Products--($/bbl)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
DISTILLATES
LS Diesel............... 18.94 20.69 21.66 22.39 22.85 23.09 23.35 23.60
Jet Fuel................ 19.45 21.16 22.12 22.84 23.30 23.55 23.80 24.07
LPG
Propane................. 11.67 12.65 13.22 13.63 13.91 14.16 14.36 14.55
Isobutane............... 15.13 16.35 17.10 17.61 17.93 18.04 18.23 18.41
Normal Butane........... 12.45 13.57 14.27 14.73 15.02 15.12 15.28 15.44
UNFINISHED
Coker Propane Propylene
Mix.................... 13.94 15.28 16.39 16.88 17.22 17.48 17.71 17.91
Coker Butane Butylene
Mix.................... 15.41 16.87 17.72 18.36 18.78 19.01 19.23 19.46
Penhex.................. 14.36 15.60 16.31 16.84 17.18 17.34 17.53 17.73
Virgin Diesel........... 17.14 18.84 19.79 20.50 20.95 21.18 21.43 21.68
Naphtha--Sour........... 17.05 18.73 19.61 20.27 20.70 20.93 21.17 21.42
Heavy Naphtha........... 19.82 21.50 22.38 23.05 23.47 23.70 23.95 24.19
ULS VGO................. 17.73 19.43 19.93 20.53 20.97 21.20 21.43 21.67
VGO..................... 15.57 17.22 17.69 18.24 18.66 18.88 19.10 19.33
OTHER PRODUCTS
Sulfur.................. 9.42 9.48 9.66 9.77 9.88 9.99 10.10 10.22
Coke.................... (0.17) -- 0.06 0.07 0.13 0.16 0.19 0.21
Produced Fuel........... 12.51 12.85 13.08 13.26 13.38 13.46 13.62 13.77
Chargestocks--($/bbl)
CRUDE
Arab Lt. ............... 14.82 16.25 16.98 17.50 17.89 18.09 18.29 18.49
Maya.................... 11.87 12.98 13.46 13.73 14.08 14.24 14.41 14.58
OTHER CHARGESTOCKS
GFU Feed................ 17.13 18.82 19.76 20.46 20.91 21.14 21.38 21.62
Hydrogen................ 28.84 29.20 29.49 30.33 30.26 30.50 30.79 31.51
</TABLE>
B-49
<PAGE>
TABLE V-11
PORT ARTHUR COKER COMPANY L.P.
BASE CASE
REVENUE AND FEEDSTOCK COST FORECAST
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
Product Revenue
<S> <C> <C> <C> <C> <C> <C> <C> <C>
DISTILLATES
LS Diesel............. 264.6 306.5 322.6 315.2 340.4 342.1 347.7 332.3
Jet Fuel.............. 178.7 203.3 216.6 211.4 228.2 226.3 233.2 222.8
------- ------- ------- ------- ------- ------- ------- -------
SUBTOTAL--Distillates. 443.4 509.8 539.3 526.6 568.6 568.4 580.9 555.1
LPG
Propane............... 4.6 5.2 5.6 5.4 5.9 5.8 6.1 5.8
Isobutane............. 1.9 2.2 2.3 2.3 2.4 2.4 2.5 2.4
Normal Butane......... 9.5 10.8 11.7 11.4 12.3 12.1 12.5 11.9
------- ------- ------- ------- ------- ------- ------- -------
SUBTOTAL--LPG......... 16.1 18.2 19.6 19.1 20.6 20.3 21.0 20.1
UNFINISHED
Coker Propane
Propylene
Mix.................. 10.6 12.1 13.2 12.9 13.9 13.8 14.3 13.7
Coker Butane Butylene
Mix.................. 8.4 9.6 10.3 10.1 10.9 10.8 11.2 10.7
Penhex................ 47.6 53.9 57.6 56.2 60.7 59.9 61.9 59.2
Virgin Diesel......... 46.0 48.4 56.6 55.4 59.9 54.4 61.3 58.6
Naphtha--Sour......... 214.9 246.8 263.4 257.3 278.0 275.8 284.3 271.8
Heavy Naphtha......... 26.8 29.8 32.3 31.4 33.9 32.9 34.6 33.0
ULS VGO............... 65.6 75.4 78.6 76.5 82.7 82.3 84.6 80.8
VGO................... 248.1 287.7 300.3 292.7 316.9 315.4 324.4 310.2
------- ------- ------- ------- ------- ------- ------- -------
SUBTOTAL--Unfinished.. 668.0 763.7 812.4 792.7 856.9 845.4 876.4 838.0
OTHER PRODUCTS
Sulfur................ 4.2 4.4 4.6 4.4 4.7 4.7 4.8 4.6
Coke.................. (1.1) -- 0.4 0.5 0.9 1.1 1.3 1.4
Produced Fuel......... 19.6 20.3 21.1 20.1 21.6 21.3 21.9 21.1
------- ------- ------- ------- ------- ------- ------- -------
SUBTOTAL--
Other Products....... 22.8 24.8 26.1 25.0 27.2 27.0 28.1 27.2
------- ------- ------- ------- ------- ------- ------- -------
TOTAL PRODUCT
REVENUE............... 1,150.2 1,316.5 1,397.4 1,363.4 1,473.3 1,461.2 1,506.4 1,440.4
Chargestock Cost
CRUDE
Arab Lt. ............. 204.2 234.0 249.3 242.8 262.7 260.5 268.5 256.7
Maya--Market.......... 654.2 747.6 790.3 762.3 827.1 820.5 846.3 809.3
------- ------- ------- ------- ------- ------- ------- -------
SUBTOTAL--Crude....... 858.4 981.6 1,039.6 1,005.2 1,089.8 1,081.0 1,114.8 1,066.0
OTHER CHARGESTOCKS
GFU Feed.............. 9.5 11.1 11.7 11.4 12.3 12.5 12.6 12.1
Hydrogen.............. 35.3 37.4 38.6 37.5 39.6 39.1 40.3 39.0
------- ------- ------- ------- ------- ------- ------- -------
SUBTOTAL--Other
Chargestocks......... 44.8 48.5 50.2 48.9 51.9 51.6 52.9 51.0
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CHARGESTOCK COST. 903.2 1,030.1 1,089.8 1,054.1 1,141.7 1,132.6 1,167.7 1,117.0
</TABLE>
B-50
<PAGE>
TABLE V-12
PORT ARTHUR COKER COMPANY L.P.
BASE CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,150.2 1,316.5 1,397.4 1,363.4 1,473.3 1,461.2 1,506.4 1,440.4
Total Chargestock Cost.. 903.2 1,030.1 1,089.8 1,054.1 1,141.7 1,132.6 1,167.7 1,117.0
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 247.0 286.4 307.5 309.3 331.6 328.6 338.7 323.4
PMI Contract Coker Gross
Margin
Guarantee.............. 43.8 19.0 (2.7) (22.6) (28.0) (23.9) -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 290.8 305.4 304.8 286.7 303.6 304.6 338.7 323.4
Variable Operating Ex-
penses................. 26.5 27.9 28.5 28.0 29.1 28.9 29.6 29.0
Fixed Operating Ex-
penses................. 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 58.5 61.4 63.2 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (69.7) (72.0) (73.4) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 81.9 84.7 86.8 83.5 87.7 89.1 92.6 92.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 208.8 220.7 218.0 203.2 215.9 215.5 246.1 231.2
Other Cash Items
Interest Income......... 1.9 2.7 3.1 3.1 2.1 2.3 3.6 5.3
Cash Taxes.............. -- (18.3) (32.1) (27.1) (48.5) (53.6) (68.1) (50.6)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 1.6 5.7 5.4 5.0 1.4 (6.4) (0.7) (0.7)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.4) (21.9) (31.3) (31.9) (55.8) (74.4) (76.0) (63.0)
Cash Flow Available For
Debt Service........... 204.4 198.9 186.7 171.3 160.0 141.2 170.1 168.2
Debt Service(1)
Interest/Financing Fees. 70.4 57.1 44.4 33.3 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 29.0 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 82.8 101.6 73.4 63.9 74.6 68.8 57.1 72.8
DSCR.................... 2.5 2.0 2.5 2.7 2.1 2.1 3.0 2.3
Average................. 2.4
Minimum................. 2.0
Debt Amortization Sched-
ule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 31.6 20.1 9.0 0.8
Principal Payment--
Scheduled.............. 12.4 35.8 8.1
Principal Payment--
Sweep.................. 95.8 73.0 85.0 15.0
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-51
<PAGE>
TABLE V-13
PORT ARTHUR COKER COMPANY L.P.
BASE CASE
SOURCES AND USES
<TABLE>
<CAPTION>
Project Cost
---------------------
Total Total Total
PACC Clark Project
----- ----- -------
(Dollars in
Millions)
Use of Funds
<S> <C> <C> <C>
EPC Costs............................................... 543.9 92.0 635.9
Project Contingency..................................... 28.0 28.0
Taxes and Import Duties................................. 5.0 5.0
Project Team Cost....................................... 26.0 26.0
Startup Cost (includes initial Cat & Chem).............. 14.6 14.6
----- ----- -----
Total Cash Construction Cost.......................... 591.5 118.0 709.5
Transfer of Value....................................... 2.2 (2.2)
Interest During Construction............................ 89.7 89.7
Interest Income......................................... (0.9) (0.9)
Legal/Consulting/Other Fees............................. 11.4 2.0 13.4
Financing Expenses...................................... 21.1 21.1
----- ----- -----
Total Uses............................................ 715.0 117.8 832.8
Sources of Funds
Bank Debt............................................... 325.0 325.0
Capital Markets......................................... 255.0 255.0
Cash Equity............................................. 135.0 117.8 252.8
----- ----- -----
Total Sources......................................... 715.0 117.8 832.8
</TABLE>
B-52
<PAGE>
TABLE V-14
PORT ARTHUR COKER COMPANY L.P.
BASE CASE WITHOUT PMI CONTRACT
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,150.2 1,316.5 1,397.4 1,363.4 1,473.3 1,461.2 1,506.4 1,440.4
Total Chargestock Cost.. 903.2 1,030.1 1,089.8 1,054.1 1,141.7 1,132.6 1,167.7 1,117.0
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 247.0 286.4 307.5 309.3 331.6 328.6 338.7 323.4
PMI Contract Coker Gross
Margin
Guarantee.............. -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 247.0 286.4 307.5 309.3 331.6 328.6 338.7 323.4
Variable Operating Ex-
penses................. 26.5 27.9 28.5 28.0 29.1 28.9 29.6 29.0
Fixed Operating Ex-
penses................. 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 58.5 61.4 63.2 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (69.7) (72.0) (73.4) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 81.9 84.7 86.8 83.5 87.7 89.1 92.6 92.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 165.1 201.7 220.7 225.8 243.9 239.5 246.1 231.2
Other Cash Items
Interest Income......... 1.5 2.2 3.1 3.1 2.1 2.3 3.3 3.7
Cash Taxes.............. -- -- (24.7) (34.5) (58.9) (62.5) (68.0) (50.0)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 1.6 5.7 5.4 5.0 1.4 (6.4) (0.7) (0.7)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.8) (4.1) (23.9) (39.3) (66.3) (83.3) (76.2) (64.0)
Cash Flow Available For
Debt Service........... 160.3 197.6 196.8 186.5 177.6 156.2 169.9 167.2
Debt Service(1)
Interest/Financing Fees. 71.5 61.5 48.2 35.0 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 36.7 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 83.9 106.0 84.8 65.6 74.6 68.8 57.1 72.8
DSCR.................... 1.9 1.9 2.3 2.8 2.4 2.3 3.0 2.3
Average................. 2.4
Minimum................. 1.9
Debt Amortization Sched-
ule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 32.3 23.9 12.7 2.5
Principal Payment--
Scheduled.............. 12.4 35.8 15.8
Principal Payment--
Sweep.................. 61.9 68.7 84.0 46.5
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-53
<PAGE>
TABLE V-15
PORT ARTHUR COKER COMPANY L.P.
BACKCAST CASE
PRODUCT AND FEEDSTOCK PRICING
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Historical Year Applied...... 1989 1990 1991 1992 1993 1994 1995 1996
Products-- ($/bbl)
DISTILLATES
LS Diesel.................. 21.75 27.41 24.23 23.07 21.11 19.87 20.35 25.03
Jet Fuel................... 23.14 30.37 25.33 23.93 22.12 20.57 20.69 25.40
LPG
Propane.................... 8.47 13.64 13.34 12.48 11.95 11.56 12.48 16.45
Isobutane.................. 14.82 20.39 19.40 18.98 16.25 14.95 16.58 20.58
Normal Butane.............. 10.83 16.44 16.48 14.78 13.93 13.32 14.75 18.17
UNFINISHED
Coker Propane Propylene
Mix....................... 13.24 18.06 17.55 15.27 14.36 15.56 16.72 19.62
Coker Butane Butylene Mix.. 12.83 18.42 17.94 16.88 15.09 14.13 15.67 19.37
Penhex..................... 15.72 20.85 19.23 17.45 15.31 13.85 15.48 18.98
Virgin Diesel.............. 20.51 26.17 22.99 21.84 19.87 18.02 18.51 23.19
Naphtha--Sour.............. 20.66 26.80 24.15 21.32 18.86 17.53 18.53 22.20
Heavy Naphtha.............. 23.41 29.56 26.90 24.08 21.64 20.29 21.29 24.98
ULS VGO.................... 20.66 25.81 22.29 21.37 19.72 18.38 19.85 23.83
VGO........................ 18.12 23.27 19.04 19.15 17.44 16.43 17.92 21.70
OTHER PRODUCTS
Sulfur..................... 24.00 21.83 18.54 11.97 7.45 6.55 8.32 8.88
Coke....................... 0.47 0.69 (0.19) 0.06 (0.20) 0.11 0.51 0.87
Produced Fuel.............. 10.36 10.52 9.26 10.87 12.98 11.38 9.79 15.00
Chargestocks-- ($/bbl)
CRUDE
Arab Lt.................... 18.17 22.49 19.53 18.90 16.70 15.97 17.61 20.73
Maya....................... 15.70 18.11 14.01 14.24 12.96 13.44 15.40 18.35
OTHER CHARGESTOCKS
GFU Feed................... 20.51 26.17 22.99 21.84 19.87 18.02 18.51 23.19
Hydrogen................... 24.71 24.73 22.17 25.76 29.50 26.52 23.47 33.86
</TABLE>
B-54
<PAGE>
TABLE V-16
PORT ARTHUR COKER COMPANY L.P.
BACKCAST CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
Historical Year Applied 1989 1990 1991 1992 1993 1994 1995 1996
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,340.8 1,798.1 1,585.7 1,416.4 1,362.5 1,250.7 1,341.1 1,548.1
Total Chargestock Cost.. 1,156.3 1,414.1 1,152.1 1,097.0 1,056.7 1,049.1 1,204.7 1,361.4
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 184.6 384.1 433.6 319.3 305.8 201.6 136.4 186.7
PMI Contract Coker Gross
Margin Guarantee....... 32.6 (34.2) -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 217.2 349.8 433.6 319.3 305.8 201.6 136.4 186.7
Variable Operating
Expenses............... 22.8 23.2 21.6 23.9 28.4 25.3 22.7 31.1
Fixed Operating
Expenses............... 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 53.4 54.7 53.5 53.8 61.3 57.4 54.4 65.8
Processing Fees......... (68.0) (69.7) (70.1) (72.2) (75.8) (75.6) (75.6) (80.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 75.0 75.6 73.6 75.6 86.3 82.0 79.4 96.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 142.2 274.2 360.0 243.6 219.5 119.6 57.0 90.5
Other Cash Items
Interest Income......... 1.7 2.0 5.9 6.3 5.1 6.9 8.0 8.6
Cash Taxes.............. -- (12.0) (83.8) (43.5) (51.0) (19.7) -- (7.9)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 3.6 8.4 -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (2.6) (13.5) (85.6) (50.0) (56.7) (29.5) (2.9) (16.4)
Cash Flow Available For
Debt Service........... 139.6 260.7 274.4 193.6 162.8 90.1 54.1 74.2
Debt Service(1)
Interest/Financing Fees. 72.4 61.7 48.6 33.2 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 36.7 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 84.8 106.2 85.3 63.8 74.6 68.8 57.1 72.9
DSCR.................... 1.6 2.5 3.2 3.0 2.2 1.3 0.9(2) 1.0
Average................. 2.0
Minimum................. 0.9
Debt Amortization
Schedule
Capital Markets.........
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 32.9 24.1 13.1 0.7
Principal Payment--
Scheduled.............. 12.4 35.8 15.8
Principal Payment--
Sweep.................. 47.4 76.0 125.4 12.2
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
(2) Cash flow shortfall of $3.0 million. PMI Account fully funded at $50.0
million.
B-55
<PAGE>
TABLE V-17
PORT ARTHUR COKER COMPANY L.P.
BACKCAST CASE WITHOUT PMI CONTRACT
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
Historical Year Applied 1989 1990 1991 1992 1993 1994 1995 1996
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,340.8 1,798.1 1,585.7 1,416.2 1,362.5 1,250.7 1,341.1 1,548.1
Total Chargestock Cost.. 1,156.3 1,414.1 1,152.1 1,097.0 1,056.7 1,049.1 1,204.7 1,361.4
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 184.6 384.1 433.6 319.3 305.8 201.6 136.4 186.7
PMI Contract Coker Gross
Margin Guarantee....... -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 184.6 384.1 433.6 319.3 305.8 201.6 136.4 186.7
Variable Operating
Expenses............... 22.8 23.2 21.6 23.9 28.4 25.3 22.7 31.1
Fixed Operating
Expenses............... 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 53.4 54.7 53.5 53.8 61.3 57.4 54.4 65.8
Processing Fees......... (68.0) (69.7) (70.1) (72.2) (75.8) (75.6) (75.6) (80.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 75.0 75.6 73.6 75.6 86.3 82.0 79.4 96.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 109.6 308.5 360.0 243.6 219.5 119.6 57.0 90.5
Other Cash Items
Interest Income......... 1.5 1.8 3.4 3.3 2.6 4.9 5.9 6.4
Cash Taxes.............. -- (11.2) (85.1) (42.7) (50.0) (18.9) -- (7.5)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 3.6 8.4 -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (2.8) (12.9) (89.4) (52.3) (58.3) (30.8) (5.0) (18.1)
Cash Flow Available For
Debt Service 106.8 295.6 270.6 191.3 161.3 88.8 52.1 72.4
Debt Service(1)
Interest/Financing Fees. 73.3 62.8 43.4 32.5 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 34.4 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 85.7 107.3 77.9 63.1 74.6 68.8 57.1 72.9
DSCR.................... 1.2 2.8 3.5 3.0 2.2 1.3 0.9(2) 1.0
Average................. 2.0
Minimum................. 0.9
Debt Amortization
Schedule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 33.6 25.5 7.9
Principal Payment--
Scheduled.............. 12.4 35.8 13.5
Principal Payment--
Sweep.................. 22.1 141.2 100.0
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
(2) Cash flow shortfall of $5.0 million. PMI Account funded at $37.4 million.
B-56
<PAGE>
TABLE V-18
PORT ARTHUR COKER COMPANY L.P.
DOWNSIDE CASE
PRODUCT AND FEEDSTOCK PRICING
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
Historical Year Applied 1996 1996 1996 PGI PGI PGI PGI PGI
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Products-- ($/bbl)
DISTILLATES
LS Diesel..................... 25.04 25.04 25.04 22.39 22.85 23.09 23.35 23.60
Jet Fuel...................... 25.40 25.40 25.40 22.84 23.30 23.55 23.80 24.07
LPG
Propane....................... 17.59 17.59 17.59 13.63 13.92 14.16 14.36 14.55
Isobutane..................... 21.72 21.72 21.72 17.61 17.93 18.05 18.23 18.41
Normal Butane................. 19.30 19.30 19.30 14.73 15.02 15.12 15.28 15.44
UNFINISHED
Coker Propane Propylene Mix... 19.63 19.63 19.63 16.88 17.22 17.48 17.71 17.91
Coker Butane Butylene Mix..... 20.51 20.51 20.51 18.36 18.78 19.01 19.23 19.46
Penhex........................ 19.05 19.05 19.05 16.84 17.18 17.34 17.54 17.73
Virgin Diesel................. 23.19 23.19 23.19 20.50 20.95 21.18 21.43 21.68
Naphtha--Sour................. 22.20 22.20 22.20 20.28 20.70 20.93 21.17 21.42
Heavy Naphtha................. 24.98 24.98 24.98 23.05 23.47 23.70 23.95 24.19
ULS VGO....................... 23.83 23.83 23.83 20.53 20.97 21.20 21.43 21.67
VGO........................... 21.70 21.70 21.70 18.24 18.66 18.88 19.10 19.33
OTHER PRODUCTS
Sulfur........................ 8.88 8.88 8.88 9.77 9.88 9.99 10.10 10.22
Coke.......................... 0.87 0.87 0.87 0.07 0.13 0.16 0.19 0.21
Produced Fuel................. 15.02 15.02 15.01 13.26 13.38 13.46 13.62 13.77
Chargestocks--($/bbl)
CRUDE
Arab Lt. ..................... 20.72 20.72 20.72 17.50 17.89 18.09 18.29 18.49
Maya.......................... 18.26 18.26 18.26 13.73 14.08 14.24 14.41 14.58
OTHER CHARGESTOCKS
GFU Feed...................... 23.19 23.19 23.19 20.46 20.91 21.14 21.38 21.62
Hydrogen...................... 33.64 33.64 33.64 30.33 30.26 30.50 30.79 31.51
</TABLE>
B-57
<PAGE>
TABLE V-19
PORT ARTHUR COKER COMPANY L.P.
DOWNSIDE CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
Historical Year Applied 1996 1996 1996 PGI PGI PGI PGI PGI
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,539.1 1,609.2 1,640.4 1,363.4 1,473.3 1,461.2 1,506.4 1,440.4
Total Chargestock Cost.. 1,344.7 1,406.8 1,434.1 1,054.1 1,141.7 1,132.6 1,167.7 1,117.0
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 194.3 202.4 206.3 309.3 331.6 328.6 338.7 323.4
PMI Contract Coker Gross
Margin Guarantee....... 23.9 25.4 25.9 (22.6) (28.0) (30.9) (9.0) --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 218.2 227.7 232.1 286.7 303.6 297.7 329.8 323.4
Variable Operating
Expenses............... 30.9 31.6 31.9 28.0 29.1 28.9 29.6 29.0
Fixed Operating
Expenses............... 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 64.5 66.6 68.0 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (71.7) (73.8) (75.1) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 90.3 91.8 93.5 83.5 87.7 89.1 92.6 92.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 128.0 135.9 138.6 203.2 215.9 208.6 237.2 231.2
Other Cash Items
Interest Income......... 2.0 2.3 2.8 2.9 2.1 2.3 3.0 4.7
Cash Taxes.............. -- -- -- -- (14.9) (51.0) (64.5) (50.4)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 5.9 (0.1) (0.2) 12.2 1.4 0.6 (7.6) --
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ 0.1 (9.8) (5.2) 2.3 (22.3) (64.9) (80.0) (62.7)
Cash Flow Available For
Debt Service........... 128.1 126.1 133.5 205.5 193.6 143.7 157.2 168.5
Debt Service(1)
Interest/Financing Fees. 73.5 68.0 61.6 49.8 33.9 22.4 16.8 11.1
Principal............... 12.4 44.5 52.4 85.7 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 85.9 112.5 114.0 135.5 80.4 68.8 57.1 72.8
DSCR.................... 1.5 1.1 1.2 1.5 2.4 2.1 2.8 2.3
Average................. 1.9
Minimum................. 1.1
Debt Amortization
Schedule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 33.2 28.3 23.6 16.3 5.7
Principal Payment--
Scheduled.............. 12.4 35.8 31.5 55.1
Principal Payment--
Sweep.................. 36.4 10.2 14.6 52.5 76.5
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-58
<PAGE>
TABLE V-20
PORT ARTHUR COKER COMPANY L.P.
REDUCED UTILIZATION CASE
CHARGES AND YIELDS
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Products--Volume (bpd in
thousands)
DISTILLATES
LS Diesel................... 36.4 39.6 38.8 36.6 38.8 39.6 38.8 36.6
Jet Fuel.................... 23.9 25.7 25.5 24.1 25.5 25.7 25.5 24.1
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Distillates....... 60.3 65.3 64.4 60.7 64.4 65.3 64.4 60.7
LPG
Propane..................... 1.0 1.1 1.1 1.0 1.1 1.1 1.1 1.0
Isobutane................... 0.3 0.4 0.4 0.3 0.4 0.4 0.4 0.3
Normal Butane............... 2.0 2.2 2.2 2.0 2.2 2.2 2.2 2.0
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--LPG............... 3.4 3.6 3.6 3.4 3.6 3.6 3.6 3.4
UNFINISHED
Coker Propane Propylene Mix. 2.0 2.1 2.1 2.0 2.1 2.1 2.1 2.0
Coker Butane Butylene Mix... 1.4 1.5 1.5 1.4 1.5 1.5 1.5 1.4
Penhex...................... 8.7 9.3 9.2 8.7 9.2 9.3 9.2 8.7
Virgin Diesel............... 7.0 6.9 7.5 7.1 7.5 6.9 7.5 7.1
Naphtha--Sour............... 32.8 35.2 35.0 33.0 35.0 35.2 35.0 33.0
Heavy Naphtha............... 3.6 3.8 3.9 3.7 3.9 3.8 3.9 3.7
ULS VGO..................... 9.1 9.8 9.7 9.1 9.7 9.8 9.7 9.1
VGO......................... 41.8 45.0 44.6 42.0 44.6 45.0 44.6 42.0
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Unfinished........ 106.3 113.6 113.4 106.9 113.4 113.6 113.4 106.9
OTHER PRODUCTS
Sulfur...................... 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2
Coke........................ 17.1 18.3 18.2 17.1 18.2 18.3 18.2 17.1
Produced Fuel............... 4.3 4.3 4.4 4.2 4.4 4.3 4.4 4.2
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other Products.... 22.5 23.9 23.8 22.5 23.8 23.9 23.8 22.5
----- ----- ----- ----- ----- ----- ----- -----
TOTAL PRODUCTS................ 192.6 206.4 205.2 193.4 205.2 206.4 205.2 193.5
Chargestocks--Volume (bpd in
thousands)
CRUDE
Arab Lt..................... 35.8 38.5 38.2 36.0 38.2 38.5 38.2 36.0
Maya........................ 143.3 153.8 152.9 144.1 152.9 153.8 152.9 144.1
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Crude............. 179.2 192.3 191.1 180.1 191.1 192.3 191.1 180.1
OTHER CHARGESTOCKS
GFU Feed.................... 1.5 1.7 1.6 1.5 1.6 1.7 1.6 1.5
Hydrogen.................... 3.2 3.4 3.4 3.2 3.4 3.4 3.4 3.2
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other
Chargestocks............... 4.7 5.1 5.0 4.7 5.0 5.1 5.0 4.7
----- ----- ----- ----- ----- ----- ----- -----
TOTAL CHARGESTOCKS............ 183.9 197.4 196.1 184.8 196.1 197.4 196.1 184.8
</TABLE>
B-59
<PAGE>
TABLE V-21
PORT ARTHUR COKER COMPANY L.P.
REDUCED UTILIZATION CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,094.1 1,284.2 1,329.1 1,296.7 1,401.3 1,425.3 1,432.8 1,370.0
Total Chargestock Cost.. 858.4 1,004.6 1,035.9 1,001.9 1,085.1 1,104.5 1,109.9 1,061.7
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 235.6 279.6 293.2 294.9 316.1 320.9 322.9 308.3
PMI Contract Coker Gross
Margin
Guarantee.............. 41.6 18.6 (2.5) (21.8) (26.6) (23.0) -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 277.2 298.2 290.7 273.1 289.5 297.8 322.9 308.3
Variable Operating Ex-
penses................. 26.5 27.9 28.5 28.0 29.1 28.9 29.6 29.0
Fixed Operating Ex-
penses................. 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 58.5 61.4 63.2 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (69.7) (72.0) (73.4) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 81.9 84.7 86.8 83.5 87.7 89.1 92.6 92.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 195.3 213.5 203.9 189.6 201.8 208.7 230.3 216.2
Other Cash Items
Interest Income......... 1.7 2.5 3.3 3.0 2.1 2.3 3.6 5.2
Cash Taxes.............. -- (9.8) (26.5) (21.6) (43.3) (51.1) (62.2) (45.0)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 2.1 5.2 5.3 5.1 1.0 (6.1) (0.6) (0.6)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.1) (14.2) (25.6) (26.3) (51.0) (71.7) (70.1) (57.4)
Cash Flow Available For
Debt Service........... 191.2 199.4 178.2 163.3 150.8 137.1 160.3 158.7
Debt Service(1)
Interest/Financing Fees. 70.8 58.3 45.7 34.2 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 36.7 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 83.2 102.8 82.3 64.8 74.6 68.8 57.1 72.8
DSCR.................... 2.3 1.9 2.2 2.5 2.0 2.0 2.8 2.2
Average................. 2.2
Minimum................. 1.9
Debt Amortization Sched-
ule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 31.9 21.3 10.3 1.7
Principal Payment--
Scheduled.............. 12.4 35.8 15.8
Principal Payment--
Sweep.................. 85.4 72.4 71.9 31.3
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-60
<PAGE>
TABLE V-22
PORT ARTHUR COKER COMPANY L.P.
REDUCED COKER YIELD CASE
CHARGES AND YIELDS
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Products--Volume (bpd in
thousands)
DISTILLATES
LS Diesel................... 38.3 40.6 40.8 38.5 40.8 40.6 40.8 38.5
Jet Fuel.................... 25.2 26.3 26.8 25.3 26.8 26.3 26.8 25.3
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Distillates....... 63.4 66.9 67.6 63.8 67.6 66.9 67.6 63.8
LPG
Propane..................... 1.1 1.1 1.2 1.1 1.2 1.1 1.2 1.1
Isobutane................... 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Normal Butane............... 2.1 2.2 2.2 2.1 2.2 2.2 2.2 2.1
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--LPG............... 3.5 3.7 3.8 3.6 3.8 3.7 3.8 3.6
UNFINISHED
Coker Propane Propylene Mix. 2.0 2.1 2.2 2.0 2.2 2.1 2.2 2.0
Coker Butane Butylene Mix... 1.5 1.5 1.6 1.5 1.6 1.5 1.6 1.5
Penhex...................... 9.1 9.5 9.7 9.1 9.7 9.5 9.7 9.1
Virgin Diesel............... 7.0 6.6 7.4 7.0 7.4 6.6 7.4 7.0
Naphtha--Sour............... 34.3 35.9 36.6 34.5 36.6 35.9 36.6 34.5
Heavy Naphtha............... 3.7 3.8 4.0 3.7 4.0 3.8 4.0 3.7
ULS VGO..................... 10.1 10.6 10.8 10.2 10.8 10.6 10.8 10.2
VGO......................... 43.3 45.5 46.2 43.6 46.2 45.5 46.2 43.6
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Unfinished........ 111.0 115.6 118.4 111.6 118.4 115.6 118.4 111.6
OTHER PRODUCTS
Sulfur...................... 1.2 1.3 1.3 1.2 1.3 1.3 1.3 1.2
Coke........................ 18.7 19.6 19.9 18.8 19.9 19.6 19.9 18.8
Produced Fuel............... 4.3 4.3 4.4 4.2 4.4 4.3 4.4 4.2
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other Products.... 24.2 25.2 25.7 24.2 25.7 25.2 25.7 24.2
----- ----- ----- ----- ----- ----- ----- -----
TOTAL PRODUCTS............... 202.2 211.3 215.5 203.1 215.5 211.3 215.5 203.1
Chargestocks--Volume (bpd in
thousands)
CRUDE
Arab Lt..................... 37.7 39.5 40.2 37.9 40.2 39.5 40.2 37.9
Maya........................ 150.9 157.8 160.9 151.7 160.9 157.8 160.9 151.7
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Crude............. 188.6 197.3 201.1 189.6 201.1 197.3 201.1 189.6
OTHER CHARGESTOCKS
GFU Feed.................... 1.5 1.6 1.6 1.5 1.6 1.6 1.6 1.5
Hydrogen.................... 3.3 3.5 3.6 3.4 3.6 3.5 3.6 3.4
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other
Chargestocks............... 4.9 5.1 5.2 4.9 5.2 5.1 5.2 4.9
----- ----- ----- ----- ----- ----- ----- -----
TOTAL CHARGESTOCKS 193.5 202.4 206.3 194.5 206.3 202.4 206.3 194.5
</TABLE>
B-61
<PAGE>
TABLE V-23
PORT ARTHUR COKER COMPANY L.P.
REDUCED COKER YIELD CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,144.5 1,310.0 1,390.5 1,356.6 1,466.1 1,454.0 1,499.0 1,433.4
Total Chargestock Cost.. 903.1 1,030.0 1,089.7 1,054.0 1,141.6 1,132.5 1,167.6 1,116.9
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 241.4 280.0 300.8 302.7 324.5 321.5 331.5 316.5
PMI Contract Coker Gross
Margin
Guarantee.............. 43.8 19.0 (2.7) (22.6) (28.0) (23.9) -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 285.2 299.1 298.1 280.1 296.5 297.6 331.5 316.5
Variable Operating Ex-
penses................. 26.5 27.9 28.5 28.0 29.1 28.9 29.6 29.0
Fixed Operating Ex-
penses................. 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 58.5 61.4 63.2 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (69.7) (72.0) (73.4) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 81.9 84.7 86.8 83.5 87.7 89.1 92.6 92.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 203.3 214.4 211.3 196.6 208.8 208.5 238.9 224.3
Other Cash Items
Interest Income......... 1.8 2.6 3.2 3.1 2.1 2.3 3.6 5.3
Cash Taxes.............. -- (13.5) (29.5) (24.4) (45.9) (51.0) (65.4) (48.0)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 1.6 5.7 5.4 5.0 1.4 (6.4) (0.7) (0.7)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.5) (17.2) (28.5) (29.2) (53.2) (71.7) (73.3) (60.4)
Cash Flow Available For
Debt Service........... 198.8 197.2 182.8 167.4 155.6 136.7 165.5 163.9
Debt Service(1)
Interest/Financing Fees. 70.6 57.6 45.1 33.7 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 35.1 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 83.0 102.1 80.2 64.3 74.6 68.8 57.1 72.8
DSCR.................... 2.4 1.9 2.3 2.6 2.1 2.0 2.9 2.3
Average................. 2.3
Minimum................. 1.9
Debt Amortization
Schedule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 31.7 20.6 9.7 1.2
Principal Payment--
Scheduled.............. 12.4 35.8 14.2
Principal Payment--
Sweep.................. 91.3 71.3 76.9 23.1
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-62
<PAGE>
TABLE V-24
PORT ARTHUR COKER COMPANY L.P.
REDUCED HYDROCRACKER CONVERSION CASE
CHARGES AND YIELDS
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Products--Volume (bpd in
thousands)
DISTILLATES
LS Diesel................... 37.6 39.9 40.1 37.8 40.1 39.9 40.1 37.8
Jet Fuel.................... 25.2 26.3 26.8 25.3 26.8 26.3 26.8 25.3
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Distillates....... 62.8 66.3 67.0 63.1 67.0 66.3 67.0 63.1
LPG
Propane..................... 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1
Isobutane................... 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Normal Butane............... 2.1 2.2 2.2 2.1 2.2 2.2 2.2 2.1
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--LPG............... 3.5 3.6 3.7 3.5 3.7 3.6 3.7 3.5
UNFINISHED
Coker Propane Propylene Mix. 2.1 2.2 2.2 2.1 2.2 2.2 2.2 2.1
Coker Butane Butylene Mix... 1.5 1.6 1.6 1.5 1.6 1.6 1.6 1.5
Penhex...................... 9.0 9.4 9.6 9.0 9.6 9.4 9.6 9.0
Virgin Diesel............... 7.3 7.0 7.8 7.4 7.8 7.0 7.8 7.4
Naphtha--Sour............... 34.5 36.1 36.8 34.7 36.8 36.1 36.8 34.7
Heavy Naphtha............... 3.5 3.6 3.7 3.5 3.7 3.6 3.7 3.5
ULS VGO..................... 11.0 11.5 11.7 11.1 11.7 11.5 11.7 11.1
VGO......................... 43.6 45.8 46.5 43.9 46.5 45.8 46.5 43.9
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Unfinished........ 112.5 117.1 120.0 113.1 120.0 117.1 120.0 113.1
OTHER PRODUCTS
Sulfur...................... 1.2 1.3 1.3 1.2 1.3 1.3 1.3 1.2
Coke........................ 17.9 18.8 19.1 18.0 19.1 18.8 19.1 18.0
Produced Fuel............... 4.3 4.3 4.4 4.2 4.4 4.3 4.4 4.2
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other Products.... 23.5 24.4 24.9 23.4 24.9 24.4 24.9 23.5
----- ----- ----- ----- ----- ----- ----- -----
TOTAL PRODUCTS............... 202.3 211.4 215.5 203.1 215.5 211.4 215.5 203.2
Chargestocks--Volume (bpd in
thousands)
CRUDE
Arab Lt..................... 37.7 39.5 40.2 37.9 40.2 39.5 40.2 37.9
Maya........................ 150.9 157.8 160.9 151.7 160.9 157.8 160.9 151.7
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Crude............. 188.6 197.3 201.1 189.6 201.1 197.3 201.1 189.6
OTHER CHARGESTOCKS
GFU Feed.................... 1.5 1.6 1.6 1.5 1.6 1.6 1.6 1.5
Hydrogen.................... 3.3 3.4 3.5 3.3 3.5 3.4 3.5 3.3
----- ----- ----- ----- ----- ----- ----- -----
SUBTOTAL--Other
Chargestocks............... 4.8 5.0 5.1 4.8 5.1 5.0 5.1 4.8
----- ----- ----- ----- ----- ----- ----- -----
TOTAL CHARGESTOCKS........... 193.4 202.3 206.2 194.4 206.2 202.3 206.2 194.4
</TABLE>
B-63
<PAGE>
TABLE V-25
PORT ARTHUR COKER COMPANY L.P.
REDUCED HYDROCRACKER CONVERSION CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,149.1 1,315.3 1,395.9 1,361.9 1,471.8 1,459.7 1,504.9 1,438.9
Total Chargestock Cost.. 902.1 1,029.0 1,088.7 1,052.9 1,140.5 1,131.4 1,166.5 1,115.8
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 246.9 286.3 307.2 309.0 331.3 328.3 338.4 323.1
PMI Contract Coker Gross
Margin Guarantee....... 43.8 19.0 (2.7) (22.6) (28.0) (23.9) -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 290.7 305.3 304.6 286.4 303.3 304.3 338.4 323.1
Variable Operating
Expenses............... 26.5 27.9 28.5 28.0 29.1 28.9 29.6 29.0
Fixed Operating
Expenses............... 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 58.5 61.4 63.2 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (69.7) (72.0) (73.4) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 81.9 84.7 86.8 83.5 87.7 89.1 92.6 92.2
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 208.8 220.6 217.7 202.9 215.6 215.2 245.8 230.9
Other Cash Items
Interest Income......... 1.9 2.7 3.1 3.1 2.1 2.3 3.6 5.3
Cash Taxes.............. -- (18.2) (32.0) (27.0) (48.4) (53.5) (68.0) (50.5)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 1.6 5.7 5.4 5.0 1.4 (6.4) (0.7) (0.7)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.4) (21.8) (31.2) (31.8) (55.7) (74.2) (75.9) (62.9)
Cash Flow Available For
Debt Service........... 204.3 198.8 186.5 171.1 159.8 140.9 169.9 168.1
Debt Service(1)
Interest/Financing Fees. 70.4 57.1 44.4 33.3 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 29.0 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 82.8 101.6 73.5 63.9 74.6 68.8 57.1 72.8
DSCR.................... 2.5 2.0 2.5 2.7 2.1 2.0 3.0 2.3
Average................. 2.4
Minimum................. 2.0
Debt Amortization
Schedule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 31.6 20.1 9.0 0.8
Principal Payment--
Scheduled.............. 12.4 35.8 8.1
Principal Payment--
Sweep.................. 95.7 72.4 84.8 15.2
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-64
<PAGE>
TABLE V-26
PORT ARTHUR COKER COMPANY L.P.
20% OPERATING COST INCREASE CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Product Revenue... 1,150.2 1,316.5 1,397.4 1,363.4 1,473.3 1,461.2 1,506.4 1,440.4
Total Chargestock Cost.. 903.2 1,030.1 1,089.8 1,054.1 1,141.7 1,132.6 1,167.7 1,117.0
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 247.0 286.4 307.5 309.3 331.6 328.6 338.7 323.4
PMI Contract Coker Gross
Margin
Guarantee.............. 43.8 19.0 (2.7) (22.6) (28.0) (23.9) -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 290.8 305.4 304.8 286.7 303.6 304.6 338.7 323.4
Variable Operating Ex-
penses................. 31.8 33.5 34.2 33.6 34.9 34.7 35.5 34.8
Fixed Operating Ex-
penses................. 41.2 41.3 42.0 43.0 45.0 47.2 49.9 51.3
Lease Fees.............. 31.6 32.2 32.8 33.6 34.2 34.8 35.5 36.4
Operating Fees.......... 58.5 61.4 63.2 59.4 62.3 62.6 64.0 62.9
Processing Fees......... (69.7) (72.0) (73.4) (74.1) (76.1) (77.4) (78.9) (79.7)
G&A Expense............. 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.9
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 94.1 97.1 99.5 96.3 101.0 102.8 106.8 106.5
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 196.7 208.3 205.3 190.4 202.6 201.9 231.9 216.9
Other Cash Items........
Interest Income......... 1.8 2.6 3.3 3.1 2.1 2.3 3.6 5.3
Cash Taxes.............. -- (8.1) (27.0) (21.8) (43.5) (48.5) (62.8) (45.3)
Mandatory Capex......... (3.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Turnaround Expense...... (7.5) (7.5) (7.5) (7.5) (9.9) (9.9) (9.9) (9.9)
Catalyst Adjustment..... 2.7 (2.1) 2.2 (2.9) 2.9 (2.9) 3.0 (3.1)
Other................... 1.6 5.7 5.4 5.0 1.4 (6.4) (0.7) (0.7)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.5) (11.8) (26.0) (26.6) (50.9) (69.3) (70.8) (57.6)
Cash Flow Available For
Debt Service 192.1 196.4 179.3 163.8 151.7 132.6 161.1 159.2
Debt Service(1)
Interest/Financing Fees. 70.9 58.3 45.9 34.3 28.2 22.4 16.8 11.1
Principal............... 12.4 44.5 36.7 30.6 46.4 46.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 83.2 102.8 82.6 64.9 74.6 68.8 57.1 72.8
DSCR.................... 2.3 1.9 2.2 2.5 2.0 1.9 2.8 2.2
Average................. 2.2
Minimum................. 1.9
Debt Amortization
Schedule
Capital Markets
Interest Payment........ 31.9 31.6 30.1 27.2 22.9 17.1 11.5 5.8
Principal Payment....... -- 8.7 20.9 30.6 46.4 46.4 40.3 61.7
Bank Debt
Interest Payment........ 31.9 21.2 10.5 1.8
Principal Payment--
Scheduled.............. 12.4 35.8 15.8
Principal Payment--
Sweep.................. 85.3 70.2 72.5 33.0
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-65
<PAGE>
TABLE V-27
PORT ARTHUR COKER COMPANY L.P.
STAND-ALONE FORECAST CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Product Revenue......... 1,409.4 1,544.4 1,631.6 1,635.4 1,773.2 1,759.0 1,814.7 1,730.8
Feedstock Cost.......... 1,126.4 1,233.9 1,281.3 1,235.8 1,343.1 1,332.5 1,374.5 1,311.3
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 283.0 310.5 350.3 399.6 430.1 426.5 440.2 419.5
PMI Contract Coker Gross
Margin
Guarantee.............. 47.9 18.9 (2.7) (22.2) (28.1) (32.6) -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 330.9 329.4 347.6 377.4 402.0 393.9 440.2 419.5
Fixed Costs............. 34.3 34.4 35.0 35.8 37.5 39.3 41.5 42.8
Variable Costs.......... 27.0 28.4 29.0 28.5 29.6 29.5 30.1 29.5
Net Lease/Operating
Fees................... 90.1 93.6 96.0 93.0 96.5 97.4 99.5 99.3
G&A Expenses + Mrkt
Fees................... 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 155.5 160.6 164.2 161.5 167.7 170.4 175.4 175.8
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 175.4 168.8 183.4 215.8 234.3 223.5 264.8 243.7
Other Cash Items
Interest Income......... 1.9 2.7 3.1 3.1 2.1 2.3 3.6 5.3
Turnaround Expense...... -- (1.2) (0.4) (28.5) -- (1.5) (0.1) (37.7)
Mandatory CAPEX......... (8.0) (2.3) (2.4) (2.4) (3.8) (3.9) (4.0) (4.1)
Tax..................... (13.8) -- (10.1) (22.2) (48.8) (52.5) (70.9) (53.2)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (20.0) (0.8) (9.8) (50.1) (50.6) (55.5) (71.4) (89.7)
Required Maintenance Re-
serve Acct............. 7.5 6.3 7.1 (21.0) 9.6 8.4 9.8 (27.8)
Cash Flow Available For
Debt Service........... 147.8 161.7 166.5 186.7 174.2 159.6 183.6 181.9
Debt Service(1)
Interest/Financing Fees. 74.7 68.9 61.3 54.7 36.5 23.9 18.0 12.9
Principal............... 12.4 44.5 52.4 109.2 52.1 47.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 87.1 113.4 113.7 163.9 88.7 71.3 58.2 74.6
DSCR.................... 1.7 1.4 1.5 1.1 2.0 2.2 3.2 2.4
Average DSCR............ 1.9
Minimum DSCR............ 1.1
Debt Amortization Sched-
ule
Capital Markets
Interest Payment........ 31.9 31.9 30.8 28.2 24.5 18.7 12.8 7.7
Principal Payment....... -- 8.7 20.9 29.6 46.4 47.4 40.3 61.7
Bank Debt
Interest Payment........ 34.6 29.1 23.0 19.6 6.2
Principal Payments...... 12.4 35.8 31.5 79.6 5.7
Mandatory Cash Sweep.... 6.1 36.1 20.8 45.3 51.6
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
B-66
<PAGE>
TABLE V-28
PORT ARTHUR COKER COMPANY L.P.
STAND-ALONE BACKCAST CASE
CASH FLOW AND DEBT AMORTIZATION
<TABLE>
<CAPTION>
2001 2002 2003 2004 2005 2006 2007 2008
------- ------- ------- ------- ------- ------- ------- -------
Historical Year 1989 1990 1991 1992 1993 1994 1995 1996
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Product Revenue......... 1,635.3 2,121.7 1,836.9 1,670.6 1,613.5 1,480.8 1,587.4 1,830.2
Feedstock Cost.......... 1,438.6 1,698.8 1,356.4 1,273.5 1,231.8 1,227.9 1,409.5 1,581.0
------- ------- ------- ------- ------- ------- ------- -------
Refinery Gross Margin. 196.8 423.0 480.5 397.1 381.6 252.9 177.8 249.1
PMI Contract Coker Gross
Margin Guarantee....... 35.3 (39.2) -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Total Gross Margin.... 232.1 383.7 480.5 397.1 381.6 252.9 177.8 249.1
Fixed Costs............. 23.7 24.8 25.8 27.1 29.2 31.3 32.3 32.0
Variable Costs.......... 22.1 22.7 20.0 22.4 27.2 23.4 20.3 29.5
Net Lease/Operating
Fees................... 77.7 79.2 80.5 75.7 77.3 78.4 81.4 79.6
G&A Expenses + Mrkt
Fees................... 3.7 3.6 3.6 3.5 3.4 3.4 3.5 3.4
------- ------- ------- ------- ------- ------- ------- -------
Total Expenses........ 127.2 130.3 129.8 128.7 137.1 136.5 137.5 144.5
------- ------- ------- ------- ------- ------- ------- -------
Operating Cash Flow... 104.8 253.4 350.7 268.4 244.5 116.3 40.3 104.6
Other Cash Items
Interest Income......... 2.3 3.0 3.8 3.4 2.4 2.6 3.9 5.7
Turnaround Expense...... -- (1.0) (0.4) (23.7) -- (1.2) (0.1) (30.9)
Mandatory CAPEX......... (7.1) (2.0) (2.0) (2.0) (3.1) (3.2) (3.3) (3.3)
Tax..................... -- (15.3) (72.2) (44.9) (55.1) (16.6) -- (3.8)
------- ------- ------- ------- ------- ------- ------- -------
Total Other Cash
Items................ (4.8) (15.4) (70.8) (67.2) (55.8) (18.4) 0.5 (32.3)
Required Maintenance
Reserve Acct........... 7.5 6.3 7.1 (21.0) 9.6 8.4 (27.8)
Cash Flow Available For
Debt Service........... 100.1 238.0 279.9 201.2 188.7 97.9 40.9 72.3
Debt Service(1)
Interest/Financing Fees. 74.9 73.6 54.9 47.4 29.8 23.9 18.0 12.9
Principal............... 12.4 44.5 52.4 57.0 46.4 47.4 40.3 61.7
------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.... 87.2 118.1 107.3 104.4 76.2 71.3 58.2 74.6
DSCR.................... 1.1 2.0 2.5 2.1 2.4 1.3 0.7(2) 1.3
Average DSCR............ 1.7
Minimum DSCR............ 0.7
Debt Amortization
Schedule
Capital Markets
Interest Payment........ 31.9 31.9 30.8 28.2 24.5 18.7 12.8 7.7
Principal Payment....... -- 8.7 20.9 29.6 46.4 47.4 40.3 61.7
Bank Debt
Interest Payment........ 34.9 33.6 17.1 13.7 0.1
Principal Payments...... 12.4 35.8 31.5 27.4
Mandatory Cash Sweep.... 117.9 99.0 1.0
</TABLE>
- --------
(1) Annual debt service for a given year includes July 15 debt service for
subject year and January 15 debt service for following year.
(2) Cash flow shortfall of $17.4 million. PMI Account fully funded at $50.0
million.
B-67
<PAGE>
- ----------------
APPENDIX A
- ----------------
DOCUMENTS REVIEWED
1. Maya Crude Oil Contract between Clark and PMI, dated March 10, 1998
2. Existing Crude Oil Contract Between Clark and PMI, evergreen dated January
1, 1990
3. Marine Dock and Terminating Agreement with Sun for use of docks in
Nederland, TX dated September 1, 1996
4. Air Products Hydrogen Supply Agreement, dated July 13, 1999 (substantially
negotiated)
5. Coker Complex Ground Lease, revision August 4, 1999 (substantially
negotiated)
6. Services and Supply Agreement, revision August 4, 1999 (substantially
negotiated)
7. Ancillary Equipment Site Lease and Easement Agreement, August 4, 1999
(substantially negotiated)
8. Product Purchase Agreement, August 4, 1999 (substantially negotiated)
9. Contract for Engineering, Procurement and Construction Services, July 12,
1999
10. Appendix A - Definitions to the Services & Supply Agreement; Product
Purchase Agreement; Coker Complex Ground Lease; Ancillary Equipment Site
Lease, August 4, 1999 (substantially negotiated)
11. Chevron Agreements
a.Engineering Services Agreement dated March 10, 1999
b.Proprietary Catalyst Supply Agreement dated March 18, 1999
c.Guarantee Agreement dated April 9, 1999
12. Resumes of key project personnel
13. Foster Wheeler Monthly Status Reports, last reviewed report dated July 27,
1999
14. Submissions for Purvin & Gertz' data request list dated September 1998
15. Heavy Oil Upgrade Study presentation made to Blackstone by Clark, March 5,
1998
16. Foster Wheeler Process Design Book, April 1, 1998
B-68
<PAGE>
17. Memorandum from Chevron to Clark dated August 24, 1998 on Hydrocracker
Yields
18. Memorandum from Foster Wheeler to Clark dated July 1, 1998 on Coker Yields
19. Financial Model prepared by Clark, dated August 10, 1999
20. Letter from K. Isom of Clark to Purvin & Gertz addressing cost of changing
refinery operation to a stand-alone mode, dated June 9, 1999.
21. Environmental Permits and Documentation, Environmental Safety Documentation
a. Flexible Permit Number 6825A
b. Permit Number 2303A
c. Letter dated May 12, 1999 notifying change of ownership for Permit 2303A
d. Letter from Black & Veatch LLP to Clark Refining and Marketing, Inc.
regarding remediation cost estimate for refinery in expansion areas
dated September 4, 1998.
e. USEPA Region 6 Multi-Media Inspection Executive Summary Report dated May
21, 1997
f. USEPA Region 6 RCRA Compliance Inspection Report dated May 1997
g. Chevron/Clark Agreement Article 12 Environmental Corrective Action,
Indemnification and Limitation of Claims
h. Letter No. 4610-2.17-C034 from Clark Refining & Marketing, Inc. to
Purvin & Gertz, Inc. regarding Clark Refining & Marketing Inc Heavy Oil
Upgrade Project Clark Safety Information dated April 15, 1999
22. Engineering Procurement, and Construction Agreement on a Reimbursable
Basis--Heavy Oil Upgrade Project between Clark and Foster Wheeler dated
March 24, 1998.
23. Foster Wheeler Heavy Oil Upgrade Project Estimate Summary, Revision 1 dated
March 23, 1999
24. First amendment and supplement to the Maya crude oil sales agreement,
revision August 4, 1999
25. Marine Dock and Terminaling Agreement between Sun Pipe Line /Company and
Clark Refining & Marketing, Inc., revision July 12, 1999
B-69
<PAGE>
ANNEX C
- --------------------------------------------------------------------------------
CRUDE OIL AND REFINED PRODUCT
MARKET FORECAST
- --------------------------------------------------------------------------------
Prepared For:
PORT ARTHUR COKER COMPANY L.P.
[LOGO OF PURVIN AND GERTZ INC.]
Dallas -- Houston -- Los Angeles
London -- Calgary -- Buenos Aires -- Singapore
July 13, 1999 T.J.
Manning
K.E.
Noack
<PAGE>
TABLE OF CONTENTS
I. INTRODUCTION ............................................................ 1
II. SUMMARY AND CONCLUSIONS ................................................. 2
LIGHT/HEAVY DIFFERENTIAL............................................ 3
HEAVY CRUDE OIL AVAILABILITY........................................ 4
PRODUCT DEMAND...................................................... 5
REFINERY MARGINS.................................................... 5
III. WORLD PETROLEUM SUPPLY/DEMAND BALANCE .................................. 6
WORLD PETROLEUM DEMAND.............................................. 6
OECD DEMAND...................................................... 6
NON OECD PETROLEUM DEMAND........................................ 7
OPEC AND THE PETROLEUM SUPPLY/DEMAND BALANCE......................... 7
RECENT TRENDS IN THE WORLD PETROLEUM SUPPLY/DEMAND BALANCE....... 8
WORLD PETROLEUM SUPPLY/DEMAND BALANCE METHODOLOGY.................... 8
WORLD PETROLEUM SUPPLY/DEMAND BALANCE FORECAST....................... 8
IV. U.S. ENERGY AND PETROLEUM DEMAND ........................................ 16
UNITED STATES PETROLEUM DEMAND...................................... 16
U.S. MOTOR FUEL DEMAND FORECASTS.................................... 17
METHODOLOGY..................................................... 17
REGIONAL TRAVEL................................................. 18
VEHICLE EFFICIENCIES............................................ 19
NON-HIGHWAY FUEL USE ADJUSTMENTS................................ 19
ALTERNATIVE FUELS............................................... 20
U.S. GASOLINE DEMAND............................................ 20
DIESEL/NO. 2 FUEL OIL........................................... 23
U.S. AVIATION FUELS............................................. 24
U.S. RESIDUAL FUEL OIL.......................................... 24
U.S. ASPHALT.................................................... 25
U.S. COKE....................................................... 26
U.S. OTHER PRODUCTS............................................. 26
V. HEAVY CRUDE OIL AVAILABILITY ............................................ 27
HEAVY CRUDE OIL PRODUCTION.......................................... 27
SUPPLY OF HEAVY CRUDE OIL TO THE PROJECT............................ 28
MEXICAN CRUDE OIL PRODUCTION.................................... 28
MAYA CRUDE OIL.............................................. 29
ALTERNATE SOURCES OF HEAVY CRUDE OIL SUPPLY......................... 30
VENEZUELA....................................................... 30
HEAVY CRUDE BALANCES................................................ 32
VI. DIVERSION RISKS.......................................................... 39
PRODUCTION CHANGES.................................................. 39
MARKETING OPPORTUNITIES............................................. 39
U.S. CRUDE OIL IMPORTS.......................................... 40
MAJOR CUSTOMERS................................................. 40
STRUCTURAL IMPEDIMENTS.............................................. 41
PHYSICAL LIMITATIONS............................................ 41
OWNERSHIP LIMITATIONS........................................... 41
i
<PAGE>
GEOGRAPHICAL CONSTRAINTS........................................ 41
MAJOR FACTORS LIMITING MARKET PENETRATION BY PEMEX.................. 41
REFINERY COMPLEXITY REQUIREMENT................................. 41
HIGH LEVEL OF SOUR CRUDE OIL CAPACITY UTILIZATION OF EXISTING
REFINERIES.................................................. 41
STRATEGIC AFFILIATIONS OF COMPETING PRODUCERS................... 42
VENEZUELAN EXTRA HEAVY OIL PROJECTS............................. 42
ALTERNATIVE CRUDE SUPPLY........................................ 42
VII. CRUDE OIL PRICING AND LIGHT/HEAVY DIFFERENTIAL ......................... 50
CRUDE OIL PRICING................................................... 50
LIGHT/HEAVY DIFFERENTIAL............................................ 50
FACTORS THAT AFFECT THE LIGHT/HEAVY DIFFERENTIAL................ 50
RECENT TRENDS IN THE CONVERSION CAPACITY SUPPLY/DEMAND BALANCE.. 51
RECENT TRENDS IN THE LIGHT/HEAVY DIFFERENTIAL....................... 53
VOLATILITY OF THE LIGHT/HEAVY DIFFERENTIAL...................... 53
LIGHT/HEAVY DIFFERENTIAL FORECAST............................... 55
USGC REFINERY MARGINS............................................... 55
DRIVERS OF REFINERY PROFITABILITY............................... 56
CAPACITY UTILIZATION........................................ 58
COMMODITY DRIVEN CYCLES..................................... 58
MARGIN FORECAST FOR LLS CRACKER............................. 59
REFINERY MARGINS............................................ 59
USGC PRODUCT PRICES................................................. 60
GASOLINE........................................................ 60
CONVENTIONAL GRADES......................................... 60
REFORMULATED GASOLINE....................................... 61
DISTILLATE FUELS.................................................... 61
STANDARD DISTILLATE......................................... 61
LOW SULFUR DIESEL........................................... 62
RESIDUAL FUEL OIL............................................... 62
TABLES............................................................ ii
FIGURES........................................................... iii
TABLES
III-1 INTERNATIONAL PETROLEUM DEMAND ........................................ 12
III-2 INTERNATIONAL PETROLEUM SUPPLY ........................................ 13
III-3 INTERNATIONAL PETROLEUM SUPPLY/DEMAND BALANCE ......................... 14
III-4 MAXIMUM SUSTAINABLE CAPACITY .......................................... 15
IV-1 UNITED STATES ENERGY BALANCE ........................................... 17
IV-2 UNITED STATES REFINED PRODUCT BALANCE .................................. 22
V-1 WORLD CRUDE OIL PRODUCTION BY REGION AND TYPE .......................... 34
V-2 MEXICAN CRUDE OIL BALANCES ............................................. 36
V-3 VENEZUELAN CRUDE OIL BALANCES .......................................... 37
V-4 TOTAL U.S. HEAVY SOUR CRUDE OIL SUPPLY/DEMAND .......................... 38
VI-1 SOUR CRUDE OIL IMPORTS ................................................. 43
VI-2 SOUR CRUDE IMPORTS BY SOURCE ........................................... 44
VI-3 1997 SOUR CRUDE CAPACITY UTILIZATION ................................... 46
VI-4 1996 SOUR CRUDE CAPACITY UTILIZATION ................................... 47
VI-5 MEXICO SOUR CRUDE IMPORTERS ............................................ 49
ii
<PAGE>
VII-1 INTERNATIONAL CRUDE OIL PRICES (CURRENT $/B) .......................... 63
VII-2 INTERNATIONAL CRUDE OIL PRICES (FORECAST 1999 $/B) .................... 64
VII-3 U.S. GULF COAST LIGHT SWEET CRUDE MARGINS (CURRENT $/B) ............... 65
VII-4 U.S. GULF COAST LIGHT SWEET CRUDE MARGINS (FORECAST 1999 $/B) ......... 66
VII-5 U.S. GULF COAST SOUR CRUDE MARGINS (CURRENT $/B) ...................... 67
VII-6 U.S. GULF COAST SOUR CRUDE MARGINS (FORECAST 1999 $/B) ................ 68
VII-7 U.S. PRODUCT PRICES (CURRENT $/B) ..................................... 69
VII-8 U.S. PRODUCT PRICES (FORECAST 1999 $/B) ............................... 70
FIGURES
II-1 WTI CUSHING CRUDE OIL PRICE............................................. 2
II-2 OPEC CRUDE PRODUCTION................................................... 3
II-3 WTI CUSHING MINUS MAYA FOB MEXICO....................................... 4
II-4 RELATIVE MARGIN INDICATOR FOR 29 USGC REFINERIES (PPI).................. 5
III-1 NON-OECD AND FSU DEMAND GROWTH ......................................... 7
III-2 WORLD CRUDE PRODUCTION ................................................. 9
III-3 OPEC CRUDE PRODUCTION ................................................. 10
III-4 OPEC CRUDE PRODUCTION AND QUOTA ....................................... 11
V-1 MEXICO CRUDE PRODUCTION ................................................ 28
V-2 MEXICO CRUDE EXPORTS ................................................... 29
V-3 VENEZUELA CRUDE PRODUCTION ............................................. 31
V-4 VENEZUELA CRUDE EXPORTS ................................................ 31
VII-1 WORLD CONVERSION CAPACITY CHANGES ..................................... 52
VII-2 U.S. CONVERSION CAPACITY CHANGES ...................................... 52
VII-3 WTI CUSHING MINUS MAYA FOB ............................................ 53
VII-4 WTI CUSHING MINUS MAYA FOB MEXICO (6 MONTH MOVING AVERAGE) ............ 54
VII-5 WTI CUSHING MINUS MAYA FOB MEXICO ..................................... 55
VII-6 RELATIVE MARGIN INDICATOR FOR 29 USGC REFINERIES (PPI) ................ 56
VII-7 USGC LLS CRACKING MARGINS AFTER VARIABLE COSTS ........................ 57
VII-8 USGC LLS CRACKING VARIABLE COST MARGIN ................................ 57
iii
<PAGE>
I. INTRODUCTION
Purvin & Gertz, Inc. has been retained as Market Consultant to provide a long
term crude oil and refined product forecast to be utilized in evaluating the
Clark Refining and Marketing, Inc. ("Clark") heavy oil upgrade project
("Upgrade Project") to be constructed at Clark's Port Arthur, Texas refinery.
The new process units (coker, hydrocracker, sulfur recovery) and certain
offsites are to be constructed by Port Arthur Coker Company L.P. ("PACC") while
other modifications to existing units and certain offsites construction will be
carried out by Clark. The Upgrade Project is designed to process primarily
Mexican Maya crude oil. This study provides an outlook for crude oil and
refined products supply, demand and pricing. In addition, a discussion of heavy
crude oil availability is provided, along with an analysis of the risk of
diversion of Maya crude away from the Upgrade Project.
Purvin & Gertz understands that this report may be provided to various
banking institutions, initial purchasers of the $255 million Port Arthur
Finance Corp. 12.5% Senior Notes due 2009, ratings agencies and insurance
companies in the course of securing financing. Purvin & Gertz also understands
that this report may be included as an Appendix to an Offering Memorandum
relating to the offer and sale of debt securities. Purvin & Gertz consents to
this report being provided to such entities and included in such documents,
subject to all limitations expressed therein and provided that such third
parties acknowledge and accept the statement of care and limitations of rights
and remedies in Purvin & Gertz' Standard Terms and Conditions.
Purvin & Gertz conducted this analysis and prepared this report utilizing
reasonable care and skill in applying methods of analysis consistent with
normal industry practice. Purvin & Gertz has not addressed potential year 2000
recognition problems in this analysis and the results assume zero impact from
year 2000 recognition problems. All results are based on information available
at the time of review. Changes in factors upon which the review is based could
affect the results. Forecasts are inherently uncertain because of events or
combinations of events which cannot reasonably be foreseen including the
actions of government, individuals, third parties and competitors. NO IMPLIED
WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE SHALL APPLY.
Some of the information on which this report is based is from the following
publicly available industry and government statistical publications: Platt's
Oilgram News, Oil & Gas Journal Database Memoria de Labores published by PEMEX
and Petroleum Intelligence Weekly and information from the U.S. Department of
Energy. Purvin & Gertz has utilized and relied upon such information without
verification and has assumed such information is accurate and correct in
preparation of this report. Accordingly, Purvin & Gertz makes no representation
or warranty as to the accuracy or adequacy of such information.
C-1
<PAGE>
II. SUMMARY AND CONCLUSIONS
The overall level of crude oil prices is set by the cost of production and
supply/demand pressures. If the price is too high, the supply will increase
because of the economic attractiveness of developing new reserves or producing
existing reserves at higher rates. At the same time, demand is decreased by use
of alternative fuels such as coal, natural gas, or nuclear energy, and/or by
conservation efforts. The resulting imbalance of supply versus demand forces
prices back down. In the same manner, if the price is too low, demand is
stimulated, alternative energy supply development is constrained, and adding
new reserves becomes less economical. Ultimately, the low prices cause demand
to approach capacity limits on production, and the resulting competition for
supply drives prices back up.
Since the crude oil price crash in 1986, the price of crude has fluctuated
around $20.00 per barrel. (Figure II-1). Prices increased in 1990/91 due to the
Gulf War, slowly declined through 1994, increased again in 1995/96 as strong
demand in Asia outstripped crude production increases. One of the key factors
was delays in bringing on new crude production in the North Sea.
[GRAPHIC OF FIGURE 11-1-WTI CUSHING CRUDE OIL PRICE]
The price of crude oil was beginning to slip in 1997 (Figure II-1) even
before the full impact of the Asian Financial Crisis was felt as a result of
growth in non-OPEC supplies and over production by OPEC with the return of
Iraq. Crude prices continued to weaken throughout 1998 and averaged $11.28 per
barrel in December. Prices are increasing in 1999 on the strength of the
agreement by OPEC and a few non-OPEC producers to reduce crude production. The
price of WTI averaged about $18.00 per barrel in June.
C-2
<PAGE>
We estimate that OPEC production would have to be constrained to around 80%
of capacity (Figure II-2) to bring the market back into balance. The propensity
for OPEC members to overproduce is high, so downward pressure will be there
until demand grows requiring OPEC to produce at 85 to 90% of capacity. As
shown, it will be around 2005 before OPEC production will be back up to 90% of
capacity.
[GRAPHIC OF FIGURE 11-2-OPEC CRUDE PRODUCTION]
The absolute level of crude prices has a very direct impact on the
feasibility of the upstream business but crude price differentials have a
larger impact on the economics of refinery conversion projects. The heavy/light
differential in this report is expressed as the differential between WTI at
Cushing and Maya fob Mexico.
LIGHT/HEAVY DIFFERENTIAL
. The light/heavy differential is the result of a complex balance of a
number of factors, such as:
-- Absolute and relative demand for light and heavy products.
-- Supply of heavy crude oil.
-- Conversion capacity supply/demand balance.
. In the time period of August 1987 to December 1998, the WTI/Maya
differential averaged $5.70/bbl based on Platt's Oilgram Price Report
weekly quotes.
. For the time period from January 1988 to March 1999, the six-month period
moving average of the light/heavy differential ranged from a high of
$8.90 to a low of $3.76, with an average of $5.83.
. Low oil prices and reduced supplies of heavy oil relative to conversion
capacity have caused the differential to narrow in late 1998/early 1999.
Despite these adverse conditions, the light/heavy differential averaged
about $5.00 per barrel over the past six months.
. Purvin & Gertz expects the light/heavy differential to widen from 2000 to
2005, and then remain relatively stable for the remainder of the forecast
period. The differential will widen due to a number of factors, such as:
--A rise in the price of crude oil. All other things being equal, when
the price of crude oil rises the light/heavy differential will tend to
widen.
--Resurgence of strong product demand in Asia, filling conversion
capacity.
--Increase in the rate of development of heavy oil reserves in Mexico,
Venezuela, and Canada will rapidly increase overall heavy feedstock
availability and overwhelm conversion capacity.
C-3
<PAGE>
. Purvin & Gertz forecasts the light/heavy differential over the 2000 to
2020 time period to average $6.51 per barrel in real terms and $8.18 per
barrel in nominal terms (Figure II-1). While there can be considerable
volatility in the light/heavy differential, the market fundamentals
suggest a widening light/heavy differential which will be beneficial to
the Upgrade Project.
[GRAPHIC OF FIGURE 11-3-WTI CUSHING minus MAYA FOB MEXICO]
HEAVY CRUDE OIL AVAILABILITY
. Purvin & Gertz expects adequate supplies of heavy crude oil to be
available to the Upgrade Project throughout the forecast period, given
that heavy crude production is concentrated in the Western Hemisphere and
that we expect production to increase substantially over the life of the
Upgrade Project.
. The Upgrade Project has been designed to process Maya produced by PEMEX.
Purvin & Gertz expects Maya to be abundant given PEMEX's reserves,
production levels and plans to expand production.
. If the Maya crude is diverted from the Upgrade Project, there are
alternative supplies. Although most of the other heavy crude supplies are
generally heavier than Maya (22API), they are still heavy crudes that
could be used effectively in the new coker.
--Contracts for Venezuela heavy crude could probably be obtained since
Venezuela plans to significantly increase their supply of heavy crude
after 2000.
--Contracts for Neutral Zone crude (18API) could probably be obtained
since the producers (Saudi Arabia and Kuwait) are having difficulty
placing its growing supplies.
. The risk of diversion of the Maya crude contracted to be used in the
Upgrade Project, is minimal for the following reasons:
--A program to significantly expand production of Maya is currently
underway and the extra supply will be difficult to place in the market
due to the limited capacity of complex refineries required to process
it.
--The netback for heavy crude shipments to Europe or Asia is low related
to U.S. Gulf Coast deliveries.
--Heavy crude is run in complex high conversion refineries and the
highest concentration of this type of refinery is found in the U.S. Gulf
Coast.
--The demand for heavy crude outside the U.S. is small and relates
primarily to asphalt manufacture; Purvin & Gertz does not expect this to
change during the forecast period.
--About 75% of the refinery capacity in PADDs I-III is designed for light
sweet and light sour crude. The light sweet refineries can not run
heavy, high sulfur crude like Maya due to metallurgy and product
specifications. The light sour refineries already run as heavy a slate
as is practical.
C-4
<PAGE>
--A heavy crude producer with an equity position in a refinery will
choose to run its own crude rather than purchasing from others such as
Mexico. PDVSA has equity ownership of over 900,000 B/D of refining
capacity in the U.S. (about 30% of the total heavy oil refinery capacity
in PADDs I-III) and is following an aggressive strategy to secure
markets for its heavy crude in competition with Mexico.
--Although Mexico could decide to participate in heavy oil export
cutbacks, the cutbacks are not likely to be large and would be prorated
over all of its customers. Recently, announced cutbacks have been in the
100,000 to 125,000 B/D range or about 10% of exports. The Upgrade
Project would not be materially affected by cuts of this magnitude.
PRODUCT DEMAND
. Product demand growth varies from year to year but generally averages
less than 2% annually. Gasoline growth is the key to overall product
growth since the product accounts for 40 to 50% of the total. Jet fuel is
the fastest growing product but total demand is relatively small
U.S. PETROLEUM PRODUCT DEMAND
(Million Barrels per Day)
<TABLE>
<CAPTION>
Annual %
Change
1998-
1995 1996 1997 1998 1999 2000 2005 2010 2015 2015
----- ----- ----- ----- ----- ----- ----- ----- ----- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Motor Gasoline.......... 7.79 7.89 8.02 8.20 8.39 8.51 8.89 9.42 9.68 0.98
Kerosene/Jet Fuel....... 1.55 1.64 1.66 1.65 1.70 1.74 1.94 2.13 2.31 1.99
Distillate.............. 3.21 3.37 3.44 3.44 3.55 3.65 4.03 4.43 4.83 2.02
Residual Fuel Oil....... 0.85 0.85 0.80 0.82 0.81 0.81 0.78 0.76 0.75 -0.49
Other Products.......... 4.33 4.56 4.71 4.57 4.58 4.63 5.01 5.27 5.49 1.09
Total Demand........... 17.72 18.30 18.62 18.68 19.03 19.35 20.64 22.01 23.06 1.25
Growth, % 0.03 3.27 1.72 0.31 1.89 1.65 1.30 1.29 0.94
</TABLE>
REFINERY MARGINS
. Purvin & Gertz expects refinery margins for heavy sour crude processors
to be significantly higher than for light sweet crude refineries. The
Upgrade Project will move Clark's Port Arthur refinery into the top tier
of Gulf Coast refineries (Figure II-4).
[GRAPHIC OF FIGURE 11-4-RELATIVE MARGIN INDICATOR FOR 29 USGC REFINERIES (PPI)]
C-5
<PAGE>
III. WORLD PETROLEUM SUPPLY/DEMAND BALANCE
The outlook for the world petroleum supply/demand balance is a key input into
the forecast of crude oil prices and differentials. A discussion of the
historical trends and expected future supply/demand balances is provided in
this section.
WORLD PETROLEUM DEMAND
The following table summarizes our outlook for world petroleum demand by key
regions of the world.
WORLD PETROLEUM DEMAND
(Million Barrels per Day)
<TABLE>
<CAPTION>
PROJECTED
-------------------------------------
1990 1995 1996 1997 1998 1999 2000 2005 2010 2015 2020
----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
OECD Demand
United States.......... 16.99 17.72 18.30 18.62 18.86 19.24 19.57 21.12 22.43 23.51 24.33
U.S. Territories....... 0.25 0.25 0.22 0.19 0.20 0.22 0.23 0.24 0.25 0.27 0.28
Canada................. 1.71 1.81 1.87 1.94 2.00 2.01 2.03 2.12 2.19 2.26 2.31
Mexico................. 1.76 1.82 1.90 1.94 2.05 2.07 2.10 2.23 2.36 2.49 2.58
OECD Europe............ 13.17 14.60 14.87 15.01 15.22 15.45 15.72 16.41 17.04 17.67 18.32
Japan.................. 5.29 5.71 5.76 5.71 5.51 5.53 5.66 6.21 6.67 7.12 7.52
Republic of Korea...... 1.04 2.01 2.13 2.29 1.93 1.96 2.01 2.45 2.75 2.95 3.13
Australia/New Zealand.. 0.83 0.96 0.94 0.95 0.95 0.98 1.00 1.08 1.15 1.22 1.28
----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total OECD............. 41.04 44.88 45.99 46.66 46.72 47.45 48.32 51.86 54.85 57.46 59.75
OECD Growth, %........ 0.92 1.14 2.48 1.44 0.14 1.57 1.83 1.14 1.06 0.89 0.71
Non-OECD Demand
FSU (Former Soviet
Union)................ 8.40 4.75 4.60 4.61 4.33 4.37 4.43 5.05 6.08 7.31 8.39
Eastern Europe......... 1.05 0.70 0.74 0.78 0.80 0.82 0.84 0.95 1.10 1.28 1.43
China.................. 2.32 3.33 3.67 4.09 4.16 4.28 4.50 5.86 6.89 7.97 8.87
Africa................. 1.94 2.20 2.24 2.32 2.32 2.35 2.40 2.61 2.79 2.97 3.10
Latin America.......... 3.41 4.12 4.27 4.43 4.58 4.71 4.83 5.33 5.79 6.25 6.62
Other Asia............. 4.40 5.96 6.42 6.63 6.62 6.72 7.05 8.67 10.07 11.48 12.65
Middle East............ 3.23 4.04 4.17 4.23 4.27 4.33 4.45 5.00 5.48 5.96 6.35
----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Non-OECD......... 24.75 25.10 26.10 27.08 27.08 27.58 28.50 33.46 38.20 43.23 47.42
Non-OECD Growth, %.... 0.32 3.64 4.02 3.73 0.02 1.82 3.33 2.88 2.62 2.52 1.50
Total World Demand..... 65.79 69.98 72.10 73.73 73.80 75.03 76.82 85.32 93.05 100.69 107.17
World Growth, %....... 0.70 2.02 3.03 2.27 0.09 1.66 2.38 1.82 1.69 1.58 1.06
</TABLE>
OECD DEMAND
OECD regional petroleum demand growth averaged 1.9% from 1990 to 1997. OECD
figures now formally include Mexico, Republic of Korea, the Czech Republic and
Poland. World petroleum demand growth in 1996, helped by a cold winter,
averaged about 3% or 2 million B/D. Demand grew 2.3% in 1997, gaining 1.6
million B/D. With a mild winter, OECD growth in 1997 was just above 1.4%,
whereas, in 1998, growth dropped to nearly zero due primarily to the financial
turmoil in Asia. Purvin & Gertz expects U.S. demand to grow at about 1.5%
through 2005, but to taper off to about 1% through the remainder of the
forecast period. Purvin & Gertz expects Western Europe growth to be slightly
less robust than the U.S. but will still average above 1% throughout the
forecast period.
Without the important influence of Asian growth, world demand growth was nil
in 1998. We expect OECD petroleum demand growth to be moderate through the
forecast period, rising about 1.3% through 2005 and slowing to the 1% range.
This projection assumes rising prices, slowing population growth and softening
economic growth through 2000.
C-6
<PAGE>
NON OECD PETROLEUM DEMAND
On the other hand, non-OECD petroleum demand growth (ex FSU) approached 5%
per year over the 1990 to 1997 period. Petroleum demand in the FSU collapsed
during the early 1990s, pulling down the total non-OECD trend (Figure III-1).
However, demand now appears to be stabilizing in that area although weakness
due to the current financial problems will continue in the near term. This has
resulted in total world growth rates rising in recent years.
As a result of the Asian financial crisis, Asian demand declined in 1998
whereas Asian growth from 1990 to 1997 contributed 5.8 million B/D to the total
world growth of 7.9 million B/D or 73% of the world increase. Asia's growth
averaged 5.1% per year.
[GRAPHIC OF FIGURE 111-1-NON-OECD AND FSU DEMAND GROWTH]
OPEC AND THE PETROLEUM SUPPLY/DEMAND BALANCE
The following table summarizes our outlook for the world petroleum
supply/demand balances and the impact we expect OPEC to have on the balance.
WORLD PETROLEUM SUPPLY/DEMAND BALANCE
(Million Barrels per Day)
<TABLE>
<CAPTION>
PROJECTED
-------------------------------------
1990 1995 1996 1997 1998 1999 2000 2005 2010 2015 2020
----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Petroleum Demand
OECD................... 41.04 44.88 45.99 46.66 46.72 47.45 48.32 51.86 54.85 57.46 59.75
Non-OECD............... 24.75 25.10 26.10 27.08 27.08 27.58 28.50 33.46 38.20 43.23 47.42
----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total World Demand..... 65.79 69.98 72.10 73.73 73.80 75.03 76.82 85.32 93.05 100.69 107.17
Demand Growth, %....... 0.70 2.02 3.03 2.27 0.09 1.66 2.38 1.82 1.69 1.58 1.06
Petroleum Supply
OPEC Crude............. 22.40 25.18 26.13 26.94 27.83 26.50 26.38 33.02 36.94 42.60 46.38
OPEC NGL............... 1.28 1.51 1.50 1.59 1.70 1.70 1.80 1.95 2.21 2.58 2.99
OPEC Condensates....... 0.70 0.80 0.89 1.04 1.09 1.10 1.25 1.35 1.56 1.81 2.09
NON-OPEC Crude......... 37.46 36.43 37.30 38.00 38.18 39.22 39.96 40.77 42.86 43.25 43.90
Non-OPEC NGL........... 3.29 3.81 3.92 3.99 4.05 4.22 4.54 5.06 5.85 6.50 6.93
Non-OPEC Condensates... 0.24 0.47 0.54 0.59 0.61 0.63 0.75 1.06 1.32 1.53 1.76
Process Gain/Other(1).. 1.85 2.04 2.13 2.15 2.18 2.25 2.29 2.42 2.59 2.71 1.65
----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total World Supply..... 67.22 70.24 72.40 74.29 75.64 75.63 76.96 85.62 93.34 100.98 107.38
Inventory, Build/Draw.. 1.43 0.27 0.31 0.56 1.83 0.59 0.14 0.30 0.30 0.28 0.21
</TABLE>
- --------
Notes: (1) Sum of process gain and other hydrocarbon supplies including non-
petroleum synthetics and oxygenates.
C-7
<PAGE>
RECENT TRENDS IN THE WORLD PETROLEUM SUPPLY/DEMAND BALANCE
OPEC crude oil production bottomed in 1985 at only 16 million B/D as demand
growth remained flat and non-OPEC supplies continued to grow with high crude
oil prices. This trend intensified competitive pressures to the breaking point
and world petroleum prices collapsed in early 1986. The collapse resulted in a
reversal of both demand and non-OPEC supply trends. The lower prices enhanced
demand internationally and non-OPEC crude oil production, especially in the
U.S., decreased as a result of the change. Thus, demand for OPEC crude
benefited from both sides of the balance.
By 1990, OPEC output had increased to 23.2 million B/D, a 48% increase
relative to the low point in 1985. The growth over that period benefited
significantly from the shock effect of the price change and it was enhanced by
strong economic growth in most regions of the world.
In 1998/99, demand for OPEC crude declined significantly as a result of Asia
financial crisis and continued growth in non-OPEC crude. In response to
decreased world demand for OPEC crude oil, OPEC members entered into a
production limitation agreement in 1998 intended to reduce production in an
attempt to maintain stable prices through the end of the decade.
WORLD PETROLEUM SUPPLY/DEMAND BALANCE METHODOLOGY
Given the projected outlook for petroleum demand, a world petroleum balance
can be derived by balancing the projected availability of crude oil and other
petroleum supplies from non-OPEC suppliers against anticipated OPEC crude oil
production. This methodology assumes that non-OPEC suppliers will produce to
their maximum capability in the longer term. The detailed supply balances and
projections are shown in Tables III-1 through III-3.
WORLD PETROLEUM SUPPLY/DEMAND BALANCE FORECAST
While economic growth will continue and petroleum demand will be robust, OPEC
crude oil requirements are expected to decline in the near term due to the
rapid increases in non-OPEC output and other supplies through the end of this
decade. The Asian downturn will have a particularly negative effect on demand
over the next several years. As a result, short term upward price pressure
should be non-existent.
C-8
<PAGE>
In the longer term, increasing demand and a slower rise in non-OPEC output
will allow OPEC countries to once again regain market share (Figure III-2). We
expect that future OPEC capacity will be sufficient to accommodate our forecast
of increased crude oil demands at the forecast price levels. We anticipate that
most of this increased OPEC production will come from the large reserve-base
countries in the Middle East and Venezuela. Our forecast also is predicated on
non-OPEC supplies increasing to the levels shown in our balances (Table III-2)
with OPEC supplies expanding at a rate such that OPEC is able to operate
between 90% and 95% of its production capacity.
[GRAPHIC OF FIGURE 111-2-WORLD CRUDE PRODUCTION]
C-9
<PAGE>
Figure III-3 shows our forecast for OPEC crude oil production, expected
maximum productive capacity, and the implied utilization rate of this capacity.
The lower line represents capacity utilization of 80%. When the utilization
rate is high, upward price pressure is likely to result. On the other hand, if
production requirements fall to below 80%, as occurred during the early 1980s
and again in 1998, then crude prices tend to be volatile and weaken
significantly. Currently, production requirements are below 80% and we expect
them to remain at these levels through this decade, improving only beyond that
point.
[GRAPHIC OF FIGURE 111-3-OPEC CRUDE PRODUCTION]
Our present assumptions regarding individual OPEC country production
capacities over the forecast period are shown in Table III-4. Capacity
expansion plans are constantly changing depending on pricing trends, budgetary
considerations and financing availability. Saudi Arabia's plans over the last
few years have been moderated strongly due to budgetary considerations and our
outlook reflects a conservative growth pattern for total capacity. Saudi Arabia
is concentrating on capacity of highest value crudes. We believe Saudi Arabia
will try to maintain extra capacity relative to total OPEC requirements as a
buffer to potential political events. Due to the increase in demand and easing
non-OPEC production increases in the outer years, it may eventually become more
difficult for Saudi Arabia to achieve the desired buffer level, tightening the
market and increasing OPEC utilization. We have reflected this in our forecast.
C-10
<PAGE>
Purvin & Gertz uses these production capacities, along with anticipated OPEC
production quotas, as a guideline to determine the projected production of each
country. Historically, output from many OPEC countries (with the exception of
Saudi Arabia, Kuwait and the UAE) has exceeded the quota levels (Figure III-4).
OPEC crude production is being constrained in the short term by agreements to
cut production, rather than new quotas. In March 1999, OPEC (excluding Iraq)
agreed to cut production to 22.965 million B/D. OPEC appears to be producing
very close to these targets.
[GRAPHIC OF FIGURE 111-4-OPEC CRUDE PRODUCTION AND QUOTA]
C-11
<PAGE>
TABLE III-1
INTERNATIONAL PETROLEUM DEMAND
(Million Barrels Per Day)
<TABLE>
<CAPTION>
Projected
Est. -------------------------------------------------------------
1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2010 2015 2020
OECD DEMAND ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
United States......... 16.99 17.72 18.30 18.62 18.86 19.24 19.57 19.88 20.18 20.49 20.80 21.12 22.43 23.51 24.33
U.S. Territories...... 0.25 0.25 0.22 0.19 0.20 0.22 0.23 0.23 0.23 0.24 0.24 0.24 0.25 0.27 0.28
Canada................ 1.71 1.81 1.87 1.94 2.00 2.01 2.03 2.05 2.07 2.09 2.10 2.12 2.19 2.26 2.31
Mexico................ 1.76 1.82 1.90 1.94 2.05 2.07 2.10 2.13 2.15 2.18 2.20 2.23 2.36 2.49 2.58
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Sub-Total North
America............. 20.71 21.60 22.29 22.69 23.10 23.55 23.93 24.29 24.63 24.99 25.35 25.71 27.24 28.52 29.50
OECD Europe (1)....... 13.17 14.60 14.87 15.01 15.22 15.45 15.72 15.94 16.09 16.23 16.36 16.41 17.04 17.67 18.32
Japan................. 5.29 5.71 5.76 5.71 5.51 5.53 5.66 5.83 5.95 6.01 6.11 6.21 6.67 7.12 7.52
Republic of Korea..... 1.04 2.01 2.13 2.29 1.93 1.96 2.01 2.09 2.18 2.31 2.38 2.45 2.75 2.95 3.13
Australia/New Zealand. 0.83 0.96 0.94 0.95 0.95 0.98 1.00 1.02 1.03 1.05 1.06 1.08 1.15 1.22 1.28
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Sub-Total Pacific.... 7.16 8.68 8.83 8.95 8.40 8.46 8.67 8.94 9.17 9.37 9.56 9.74 10.57 11.28 11.93
Total OECD........... 41.04 44.88 45.99 46.66 46.72 47.45 48.32 49.17 49.89 50.58 51.27 51.86 54.85 57.46 59.75
Demand Growth, %... 0.92 1.14 2.48 1.44 0.14 1.57 1.83 1.76 1.45 1.40 1.36 1.14 1.06 0.89 0.71
NON-OECD DEMAND
- ---------------
FSU................... 8.40 4.75 4.60 4.61 4.33 4.37 4.43 4.51 4.61 4.73 4.88 5.05 6.08 7.31 8.39
East Europe........... 1.05 0.70 0.74 0.78 0.80 0.82 0.84 0.85 0.87 0.90 0.92 0.95 1.10 1.28 1.43
China................. 2.32 3.33 3.67 4.09 4.16 4.28 4.50 4.77 5.04 5.36 5.63 5.86 6.89 7.97 8.87
Other Asia............ 4.40 5.96 6.42 6.63 6.62 6.72 7.05 7.45 7.78 8.09 8.39 8.67 10.07 11.48 12.65
Latin America......... 3.41 4.12 4.27 4.43 4.58 4.71 4.83 4.94 5.04 5.15 5.24 5.33 5.79 6.25 6.62
Middle East........... 3.23 4.04 4.17 4.23 4.27 4.33 4.45 4.56 4.67 4.79 4.90 5.00 5.48 5.96 6.35
Africa................ 1.94 2.20 2.24 2.32 2.32 2.35 2.40 2.44 2.49 2.53 2.57 2.61 2.79 2.97 3.10
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Non-OECD....... 24.75 25.10 26.10 27.08 27.08 27.58 28.50 29.53 30.50 31.54 32.53 33.46 38.20 43.23 47.42
Demand Growth, %
Non-OECD........... 0.32 3.64 4.02 3.73 0.02 1.82 3.33 3.61 3.31 3.41 3.12 2.88 2.62 2.52 1.50
TOTAL WORLD DEMAND.... 65.79 60.98 72.10 73.73 73.80 75.03 76.82 78.70 80.39 82.13 83.80 85.32 93.05 100.69 107.17
Demand Growth, %... 0.70 2.02 3.03 2.27 0.09 1.66 2.38 2.45 2.15 2.16 2.04 1.82 1.69 1.58 1.06
</TABLE>
- ------
Notes: (1) Countries include Hungary, Poland and Czech Republic.
C-12
<PAGE>
TABLE III-2
INTERNATIONAL PETROLEUM SUPPLY
(Million Barrels Per Day)
<TABLE>
<CAPTION>
PROJECTED
Est. -------------------------------------------------------------
CRUDE OIL PRODUCTION 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2010 2015 2020
-------------------- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Mideast OPEC
Saudi Arabia......... 6.26 7.98 8.06 7.97 8.09 7.60 7.42 8.00 8.70 8.84 9.17 9.50 10.43 11.90 12.62
Iran................. 3.19 3.60 3.60 3.60 3.59 3.35 3.31 3.40 3.50 3.57 3.65 3.71 3.92 4.40 4.90
Iraq................. 2.11 0.74 0.74 1.38 2.18 2.60 2.75 2.80 2.89 2.99 3.13 3.28 4.13 5.70 6.39
Kuwait............... 1.02 1.81 1.81 1.81 1.81 1.66 1.64 1.75 1.88 1.98 2.11 2.23 2.44 2.90 3.24
UAE.................. 1.80 2.14 2.18 2.16 2.27 2.11 2.09 2.16 2.23 2.29 2.36 2.41 2.56 2.68 2.94
Qatar................ 0.41 0.45 0.51 0.55 0.66 0.61 0.61 0.63 0.65 0.67 0.69 0.71 0.75 0.79 0.96
Neutral Zone......... 0.31 0.39 0.48 0.53 0.55 0.57 0.58 0.60 0.61 0.63 0.64 0.66 0.66 0.66 0.66
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Subtotal-Mideast
Opec............... 15.10 17.10 17.38 18.01 19.14 18.50 18.40 19.33 20.45 20.96 21.76 22.50 24.89 29.04 31.70
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Other OPEC
Venezuela............ 2.09 2.76 3.15 3.25 3.12 2.84 2.88 3.15 3.39 4.00 4.27 4.48 5.50 6.50 7.18
Nigeria.............. 1.73 1.84 2.07 2.10 2.05 1.82 1.80 1.89 1.99 2.06 2.15 2.21 2.39 2.57 2.76
Indonesia............ 1.30 1.33 1.33 1.33 1.34 1.30 1.29 1.32 1.35 1.37 1.40 1.42 1.55 1.63 1.78
Libya................ 1.40 1.40 1.39 1.40 1.38 1.28 1.27 1.31 1.36 1.39 1.43 1.46 1.56 1.68 1.78
Algeria.............. 0.79 0.75 0.81 0.85 0.82 0.76 0.75 0.80 0.84 0.88 0.92 0.95 1.06 1.18 1.68
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Subtotal-Other Opec. 7.30 8.08 8.75 8.92 8.69 8.00 7.98 8.47 8.93 9.70 10.17 10.51 12.05 13.56 15.18
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total OPEC Crude.... 22.40 25.18 26.13 26.94 27.83 26.50 26.38 27.80 29.38 30.66 31.93 33.02 36.94 42.60 46.88
Non-OPEC
United States........ 7.35 6.56 6.46 6.41 6.36 6.43 6.51 6.59 6.58 6.58 6.50 6.40 5.99 5.43 4.99
North Sea............ 3.66 5.58 6.00 5.96 5.94 6.64 7.00 6.70 6.58 6.40 6.25 6.14 6.65 5.85 5.25
Mexico............... 2.55 2.71 2.86 3.03 3.06 2.96 3.00 3.17 3.20 3.23 3.26 3.29 3.44 3.62 3.80
Oman................. 0.67 0.86 0.89 0.90 0.88 0.91 0.91 0.91 0.91 0.92 0.92 0.92 0.93 0.94 0.95
FSU.................. 11.09 6.85 6.75 6.89 6.92 6.97 6.94 6.93 6.93 7.00 7.07 7.15 8.20 9.46 10.69
Eastern Europe....... 0.33 0.26 0.25 0.25 0.24 0.23 0.23 0.22 0.22 0.22 0.21 0.21 0.19 0.18 0.18
China................ 2.77 2.99 3.14 3.25 3.21 3.26 3.30 3.35 3.39 3.43 3.47 3.51 3.67 3.77 3.88
Others 9.04 10.63 10.95 11.30 11.56 11.82 12.07 12.22 12.46 12.69 12.93 13.15 13.78 13.98 14.15
* North Sea includes
UK onshore..........
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Non-OPEC
Crude.............. 37.46 36.43 37.30 38.00 38.18 39.22 39.96 40.10 40.28 40.46 40.59 40.77 42.86 43.25 43.90
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Crude Supply.. 59.86 61.61 63.43 64.93 66.01 65.72 66.34 67.90 69.66 71.12 72.52 73.79 79.80 85.85 90.78
OTHER PETROLEUM
SUPPLY
OPEC NGL............. 1.28 1.51 1.50 1.59 1.70 1.70 1.80 1.82 1.84 1.86 1.88 1.95 2.21 2.58 2.99
OPEC Condenstate 0.70 0.80 0.89 1.04 1.09 1.10 1.25 1.28 1.33 1.37 1.41 1.35 1.56 1.81 2.09
Non-OPEC NGL......... 3.29 3.81 3.92 3.99 4.05 4.22 4.54 4.61 4.72 4.83 4.94 5.06 5.85 6.50 6.93
Non-OPEC Condensate 0.24 0.47 0.54 0.59 0.61 0.63 0.75 0.81 0.86 0.93 1.00 1.06 1.32 1.53 1.76
Process Gain......... 1.51 1.35 1.41 1.41 1.42 1.47 1.51 1.51 1.52 1.52 1.53 1.54 1.61 1.63 1.65
Other(1)............. 0.34 0.70 0.72 0.74 0.76 0.78 0.78 0.80 0.82 0.84 0.86 0.88 0.98 1.08 1.18
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Other Supply.. 7.36 8.63 8.97 9.36 9.63 9.91 10.62 10.84 11.09 11.35 11.62 11.83 13.54 15.12 16.60
TOTAL PETROLEUM
SUPPLY.............. 67.22 70.24 72.40 74.29 75.64 75.63 76.96 78.74 80.75 82.47 84.14 85.62 93.34 100.98 107.38
</TABLE>
- ------
Notes: (1) Other hydrocarbon supplies including non-petroleum synthetics and
oxygenates.
C-13
<PAGE>
TABLE III-3
INTERNATIONAL PETROLEUM SUPPLY/DEMAND BALANCE
(Million Barrels Per Day Unless Noted)
<TABLE>
<CAPTION>
Projected
Est. -------------------------------------------------------------
1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2010 2015 2020
PETROLEUM DEMAND ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
North America.... 20.71 21.60 22.29 22.69 23.10 23.55 23.93 24.29 24.63 24.99 25.35 25.71 27.24 28.52 29.50
OECD Europe...... 13.17 14.60 14.87 15.01 15.22 15.45 15.72 15.94 16.09 16.23 16.36 16.41 17.04 17.67 18.32
Pacific.......... 7.16 8.68 8.83 8.95 8.40 8.46 8.67 8.94 9.17 9.37 9.56 9.74 10.57 11.28 11.93
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total OECD...... 41.04 44.88 45.99 46.66 46.72 47.45 48.32 49.17 49.89 50.58 51.27 51.86 54.85 57.46 59.75
Non-OECD......... 24.75 25.10 26.10 27.08 27.08 27.58 28.50 29.53 30.50 31.54 32.53 33.46 38.20 43.23 47.42
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total World De-
mand........... 65.79 69.98 72.10 73.73 73.80 75.03 76.82 78.70 80.39 82.13 83.80 85.32 93.05 100.69 107.17
PETROLEUM SUPPLY
OPEC Crude....... 22.40 25.18 26.13 26.94 27.83 26.50 26.38 27.80 29.38 30.66 31.93 33.02 36.94 42.60 46.88
OPEC NGL......... 1.28 1.51 1.50 1.59 1.70 1.70 1.80 1.82 1.84 1.86 1.88 1.95 2.21 2.58 2.99
OPEC Condensates. 0.70 0.80 0.89 1.04 1.09 1.10 1.25 1.28 1.33 1.37 1.41 1.35 1.56 1.81 2.09
Non-OPEC Crude... 37.46 36.43 37.30 38.00 38.18 39.22 39.96 40.10 40.28 40.46 40.59 40.77 42.86 43.25 43.90
Non-OPEC NGL..... 3.29 3.81 3.92 3.99 4.05 4.22 4.54 4.61 4.72 4.83 4.94 5.06 5.85 6.50 6.93
Non-OPEC
Condensates..... 0.24 0.47 0.54 0.59 0.61 0.63 0.75 0.81 0.86 0.93 1.00 1.06 1.32 1.53 1.76
Process Gain..... 1.51 1.35 1.41 1.41 1.42 1.47 1.51 1.51 1.52 1.52 1.53 1.54 1.61 1.63 1.65
Other (1)........ 0.34 0.70 0.72 0.74 0.76 0.78 0.78 0.80 0.82 0.84 0.86 0.88 0.98 1.08 1.18
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total World Sup-
ply............ 67.22 70.24 72.40 74.29 75.64 75.63 76.96 78.74 80.75 82.47 84.14 85.62 93.34 100.98 107.38
Inventory,
Build/(Draw).... 1.43 0.27 0.31 0.56 1.83 0.59 0.14 0.04 0.36 0.35 0.34 0.30 0.30 0.28 0.21
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Statistical Im-
balance......... (1.23) (0.31) (0.22) (0.14) (0.04) -0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Inventory, Bil-
lion Barrels
(Ending Stocks)
OECD Industry.... 2.72 2.55 2.55 2.65 2.80 2.91 2.96 3.02 3.11 3.20 3.26 3.31 3.55 3.79 3.98
OECD Government.. 0.85 1.18 1.19 1.20 1.23 1.23 1.23 1.23 1.26 1.28 1.30 1.32 1.42 1.51 1.59
Other (2)........ 1.82 2.01 2.03 2.07 2.55 2.65 2.65 2.61 2.62 2.63 2.68 2.72 2.92 3.11 3.27
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Inventory. 5.39 5.74 5.77 5.92 6.58 6.79 6.84 6.86 6.99 7.11 7.24 7.35 7.90 8.41 8.85
Days of Supply
(3)
(Free World)
OECD Industry.... 50 42 40 41 43 44 44 44 45 45 45 45 45 45 45
OECD Government.. 16 19 19 19 19 19 18 18 18 18 18 18 18 18 18
Other............ 34 33 32 32 39 40 39 38 38 38 37 37 37 37 37
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ------ ------
Total Days of
Supply......... 100 94 91 92 102 103 102 100 100 100 100 100 100 100 100
</TABLE>
- -----
Notes:(1) Other hydrocarbon supplies including none-petroleum synthetics and
oxygenates. Excludes former CPE.
(2) Inventories outside reporting areas and floating stocks. Excludes former
CPE.
(3) Year ending stocks divided by average year demand for year totals.
C-14
<PAGE>
TABLE III-4
MAXIMUM SUSTAINABLE CAPACITY*
(Million Barrels Per Day)
<TABLE>
<CAPTION>
1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2010 2015 2020
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Mideast OPEC
- ------------
Saudi Arabia............ 8.50 9.25 9.30 9.80 10.00 10.00 10.00 10.20 10.40 10.60 10.80 11.00 11.50 13.00 13.50
Iran.................... 3.50 3.80 3.80 3.80 3.80 3.80 3.80 3.80 3.80 3.80 3.80 3.80 4.00 4.50 5.00
Iraq.................... 3.50 0.74 0.74 1.38 2.18 2.60 2.75 3.00 3.20 3.30 3.40 3.50 4.50 6.00 6.50
Kuwait.................. 1.70 2.00 2.00 2.00 2.20 2.20 2.20 2.24 2.28 2.32 2.36 2.40 2.50 3.00 3.30
UAE..................... 2.00 2.30 2.30 2.30 2.45 2.45 2.45 2.46 2.47 2.48 2.49 2.50 2.60 2.70 3.00
Qatar................... 0.45 0.40 0.51 0.65 0.70 0.70 0.70 0.71 0.72 0.73 0.74 0.75 0.75 0.80 1.00
Neutral Zone............ 0.40 0.40 0.40 0.55 0.60 0.60 0.70 0.72 0.74 0.76 0.78 0.80 0.80 0.80 1.00
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Subtotal Mideast OPEC.. 20.05 18.89 19.05 20.48 21.93 22.35 22.60 23.13 23.61 23.99 24.37 24.75 26.65 30.80 33.30
Other OPEC
- ----------
Venezuela............... 2.50 3.00 3.25 3.50 3.85 4.15 4.50 4.60 4.70 4.80 4.90 5.00 6.00 7.00 7.20
Nigeria................. 2.00 2.00 2.00 2.30 2.30 2.30 2.30 2.30 2.30 2.30 2.30 2.30 2.45 2.60 2.80
Indonesia............... 1.45 1.45 1.45 1.45 1.45 1.45 1.45 1.45 1.45 1.45 1.45 1.45 1.60 1.70 1.80
Libya................... 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.60 1.70 1.80
Algeria................. 0.81 0.81 0.83 0.85 0.90 0.95 1.00 1.00 1.00 1.00 1.00 1.00 1.10 1.20 1.80
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Subtotal Other OPEC.... 8.26 8.76 9.03 9.60 10.00 10.35 10.75 10.85 10.95 11.05 11.15 11.25 12.75 14.20 15.40
TOTAL OPEC CRUDE........ 28.31 27.65 28.08 30.08 31.93 32.70 33.35 33.98 34.56 35.04 35.52 36.00 39.40 45.00 48.70
OPEC Utilization........ 79% 91% 93% 90% 87% 81% 79% 82% 85% 87% 90% 92% 94% 95% 96%
</TABLE>
* Estimated by Purvin & Gertz, Inc.
C-15
<PAGE>
IV. U.S. ENERGY AND PETROLEUM DEMAND
This section analyzes regional U.S. refined product supply/demand balance
trends and resulting refining operating patterns. In the U.S., petroleum is the
dominant fuel (38%), but its market share is being slowly eroded. However,
since the U.S. economy is so highly developed, shifts from one energy source to
another occur very slowly (Table IV-1). Gas and solid fuels each have about 25%
of the energy market. Gas is regaining market share lost during the 1980s as it
was precluded from being used in new large boilers, so coal and nuclear energy
captured a larger share of the market. Hydropower's share is only about 2%, and
little potential growth remains. Petroleum's share of the market will continue
to erode, primarily since growth in vehicle fuel use is being constrained by
higher overall fleet efficiencies. Gas is forecast to show the strongest growth
as more gas becomes available. Residual fuel oil and thermal distillate use
have already been reduced to practical minimums, so gas for heating can only
increase with new demand growth. Nuclear power is limited by regulations and
financial problems, but it accounts for 8.5% of the total.
UNITED STATES PETROLEUM DEMAND
Demand in 1990 showed a decline for the first time since 1983. This resulted
primarily from the effects of the recession, which was significantly worsened
by the effects of the Mideast crisis. The trend continued through 1991 as the
economy had not staged a significant recovery during that period. However,
since 1991 refined product growth has averaged over 1% annually. Growth from
1995 to 1998, in fact, averaged almost 1.8% for a gain of near 1 million B/D.
Initial 1998 data indicate a small 0.3% gain. However, adjustments will bring
this figure closer to 0.8%. The reasonably strong growth, despite several years
of mild weather, reflects the continuing strong economy. Gasoline demand has
been particularly strong recently due to low prices and stagnant efficiency
gains.
U.S. PETROLEUM PRODUCT DEMAND
(Million Barrels per Day)
<TABLE>
<CAPTION>
Annual %
Change
1998-
1995 1996 1997 1998 1999 2000 2005 2010 2015 2015
----- ----- ----- ----- ----- ----- ----- ----- ----- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Motor Gasoline.......... 7.79 7.89 8.02 8.20 8.39 8.51 8.89 9.42 9.68 0.89
Kerosene/Jet Fuel....... 1.55 1.64 1.66 1.65 1.70 1.74 1.94 2.13 2.31 1.99
Distillate.............. 3.21 3.37 3.44 3.44 3.55 3.65 4.03 4.43 4.83 2.02
Residual Fuel Oil....... 0.85 0.85 0.80 0.82 0.81 0.81 0.78 0.76 0.75 -0.49
Other Products.......... 4.33 4.56 4.71 4.57 4.58 4.63 5.01 5.27 5.49 1.09
Total Demand........... 17.72 18.30 18.62 18.68 19.03 19.35 20.64 22.01 23.06 1.25
Growth, %............... 0.03 3.27 1.72 0.31 1.89 1.65 1.30 1.29 0.94
</TABLE>
C-16
<PAGE>
TABLE IV-1
UNITED STATES ENERGY BALANCE
(Thousand Tonnes Oil Equivalent)
ECONOMIC/ENERGY INDICATORS
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
--------- --------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
GDP (Bil 96$)........... 7,100.48 7,341.90 7,628.23 7,925.74 8,155.58 8,383.94 9,966.69 11,666.30 13,589.77
GDP growth (%).......... 2.30 3.40 3.90 3.90 2.90 2.80 3.00 3.50 3.10
Population (MM)......... 263.17 265.56 267.97 270.40 272.85 275.33 288.06 301.37 315.30
Population Growth (%)... 0.95 0.91 0.91 0.91 0.91 0.91 0.91 0.91 0.91
Energy Growth (%)....... 1.46 2.23 0.64 (0.04) 1.16 1.10 1.06 1.10 0.86
TOE/$GNP................ 294 291 282 271 266 262 235 212 190
Per Capita.............. 8,012 8,113 8,091 8,015 8,035 8,051 8,210 8,271 8,554
Energy% / GNP%.......... 0.63 0.65 0.17 (0.01) 0.40 0.39 0.35 0.32 0.28
ENERGY DEMAND BY TYPE
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
--------- --------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Petroleum............... 804,411 832,380 844,379 847,712 864,237 878,437 937,992 1,001,896 1,049,190
Natural Gas............. 508,673 504,153 503,795 491,676 517,778 527,915 580,487 626,110 666,522
Solid Fuels............. 475,344 494,013 506,225 513,316 495,192 494,518 525,837 543,758 566,725
Nuclear................. 186,022 186,389 173,647 185,169 185,207 185,109 186,121 184,176 179,704
Hydropower/Other........ 114,023 118,022 120,662 109,974 110,348 110,649 113,192 114,177 113,814
Total Energy............ 2,088,473 2,134,956 2,148,708 2,147,847 2,172,762 2,196,629 2,343,629 2,470,117 2,577,954
ENERGY DEMAND BY SECTOR
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
--------- --------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Industry................ 352,333 366,744 368,040 359,441 363,823 368,036 393,815 416,282 435,721
Transport............... 545,214 558,563 564,356 566,320 577,360 586,846 626,633 669,324 700,919
Res./Com./Other......... 435,744 455,771 454,834 447,602 452,118 456,402 483,301 505,545 523,607
Electricity............. 755,183 753,878 761,478 774,484 779,460 785,345 839,881 878,966 917,707
Total Energy............ 2,088,473 2,134,956 2,148,708 2,147,847 2,172,762 2,196,629 2,343,629 2,470,117 2,577,954
</TABLE>
Purvin & Gertz expects annual growth of well over 1% to continue through most
of the forecast under normal weather conditions. Purvin & Gertz expects growth
in overall distillates to average near 2% over the next decade, before slowing
to about 1.5% through the 2010 to 2015 period. Distillate growth reflects
strong gains in on-road application. Gasoline demand growth is now expected to
average 1% through the forecast. Travel should increase in the short term as
retail prices remain low relative to the peaks in 1997. However, we now expect
new technology to influence efficiencies beyond 2005. Beyond the short term,
travel will continue to increase by near 2%. Demand per capital gains for
gasoline are now expected to decrease over the forecasted period, largely as a
result of efficiency improvements and continuing increases in per capita miles
traveled. Our forecast now anticipates new car efficiency to improve over the
forecast as a result of technology changes.
Kerosene/jet fuel demand growth should show some of the strongest rates for
all products averaging nearly 2% for most of the forecast. Residual fuel oil
demand continues to fall averaging 0.5% decline for the forecast period.
Demands for all other products, including other refined products and natural
gas liquids, are expected to increase at a rate of 1% through out the forecast,
with natural gas liquids showing the largest gains. Purvin & Gertz expects
residual fuel demand to continue to decline over the forecast.
U.S. MOTOR FUEL DEMAND FORECASTS
METHODOLOGY
There are three primary driving forces behind motor fuel forecasts -- the
extent of travel, the fuel efficiency of the fleet, and the types of fuels used
in vehicles. An additional level of complexity to gasoline forecasts has been
added over the last few years with the introduction of oxygenated and
reformulated
C-17
<PAGE>
gasolines. These fuels have different efficiencies than standard fuels and each
region of the country has seen varying levels of price impact due to varying
volumetric requirements for the new fuels. Assumptions regarding alternative
motor fuels also affect the outlook for gasoline demand within the time frame
of this forecast, and trends also vary by region of the country. Therefore,
gasoline demand forecasts must account for the changing qualities and regional
differences.
The first step in calculating vehicle fuel demand is a projection of annual
vehicle miles traveled (AVMT) by PADD. Historical AVMT were broken down into
commercial (buses and multi-axle trucks) and private (automobiles, two-axle
trucks and motorcycles) categories. AVMT in each category were correlated to
population, fuel price, and per capita income. These correlations were used to
project miles traveled by PADD based on expected changes in the three
variables.
Vehicle mileage was considered on a PADD and vehicle category basis.
Historical mileage for automobiles and two-axle trucks was calculated using
aggregated AVMT and fuel data. Correlations of future mileage of those two
vehicle classes were prepared based on projected changes in new vehicle fleet
mileage, scrappage and replacement rates, as well as factors accounting for the
difference between mileage measured by EPA methods and experienced by on-road
vehicles.
Projected AVMT in the private and commercial sectors was desegregated into
the five vehicle types. The projected AVMT by vehicle type, combined with
projected mileage by vehicle type, resulted in the total fuel requirement.
Motor vehicle fuels have been grouped into three categories -- gasolines
(conventional and reformulated), distillate fuels, and alternative fuels
(methanol, electricity, LPG, and CNG). Cars and two-axle trucks are projected
to use mostly gasoline though there is a small proportion of diesel and
alternative fuel use. Motorcycles use only gasoline. Buses and multi-axle
trucks use significant amounts of both gasoline and diesel fuel. Fleet vehicles
in that class may use alternative fuels. The projected proportions of each type
of fuel by vehicle class were combined with the total fuel requirements to
determine fuel use by type.
From the forecast of key transportation variables, gasoline consumption in
the U.S. is projected to increase at a moderate pace in the longer term. Purvin
& Gertz expects the annual growth rate to average about 1.0% over the next ten
years, slowing to less than 1% by the end of the forecast period due to
moderating price increases, lower population growth, economic effects and
efficiency gains.
Underlying demand changes over recent years have been altered significantly
by the rapid increase in popularity of low MPG utility vehicles and trucks,
which expand the demand for gasoline as miles traveled increases. Also, the
lack of government initiatives increasing the required MPG for new vehicles has
resulted in stagnation of average vehicle efficiency in recent years. However,
Purvin & Gertz expects vehicle technologies now emerging to result in higher
efficiency in the future, as discussed below.
REGIONAL TRAVEL
Conforming to Federal Highway Administration (FHA) definitions, vehicles are
grouped into passenger cars, light-duty or double-axle trucks, motorcycles,
medium and heavy duty or nondouble-axle trucks, and buses. The breakdown of
miles traveled into these vehicle groups is necessary to distinguish the
different fuel requirements by each group. Using state averages of travel by
each type of vehicle, miles traveled are grouped by PADD. The forecast of
regional vehicle mileage uses motor fuel prices, population, per capita income,
and characteristics of the vehicle stocks to statistically measure past
variations in travel corresponding to changes in each of the variables. Each of
the regions possess different demographic and economic trends that influence
travel patterns for the forecast period.
Population growth obviously has a very strong influence on the number of
miles traveled on U.S. roads and highways. The table below reviews the
estimated historical data and our projections for population growth. The
forecasts are prepared on a state-by-state basis and are generally consistent
with U.S. government forecasts. Population growth is expected to decrease
moderately in the outer years.
C-18
<PAGE>
Per capita income (PCI) is also a significant factor affecting the level of
travel. Over the last five years PCI has been growing strongly as the economy
improved from the recessionary trends of the early 1990s. This has contributed
to a significant increase in miles traveled. PCI has been a rather erratic
variable, but we expect it to average about 1.2-1.3% over the forecast period.
Recent levels have been as high as 2%.
The average fuel price in each PADD is forecast consistent with our outlook
for crude and product prices. The forecast also takes into account changes in
prices in specific regions related to changing gasoline specifications under
the expected environmental restrictions. With the price collapse of 1998 and
relatively mild recovery of prices, we expect a very strong impact on miles
traveled in the near term.
Key indicators lead to positive growth for miles traveled throughout the
forecast. We expect average growth of about 2.7% until the end of the decade.
With prices stabilizing and population and PCI growth subsiding, we expect
longer term growth in vehicle miles to subside to the 1.7% range in the outer
years. Demographics and economic factors come to bear on the regional forecasts
as do the differing prices of fuels in each region, particularly as influenced
by the regional diversity in requirements for the new fuels of the future,
whether gasoline or alternate fuels.
VEHICLE EFFICIENCIES
Having now projected the extent of vehicle travel, it is necessary to analyze
how efficiently each vehicle group uses the motor fuel. Historical and
projected vehicle fuel efficiencies as miles per gallon (MPG) were developed on
a PADD-by-PADD basis.
The fleet average is based upon the replacement rates of new cars for the old
vehicles. For autos and double-axle trucks, the rate of new vehicle sales, plus
the scrappage rate of old vehicles, were combined to calculate the replacement
rate. Replacement rates are the ratio of new registrations to total vehicles
from forecasts of new car registrations and the resultant auto stock. For
double-axle trucks, the replacement rate is estimated using the auto
replacement rate. This is justified because both vehicles have similar
characteristics and data on double-axle trucks was insufficient to compute a
similar measure. For motorcycles, nondouble-axle trucks and buses, it was
assumed that the new vehicle characteristics are the same as old vehicle
characteristics.
Average fleet efficiency has not improved significantly in recent years with
the American consumers demanding larger engines and more power. In addition,
the move toward SUVs and light trucks has been dramatic. While these trends are
generally expected to continue for the foreseeable future, Purvin & Gertz
expects emerging vehicle technologies to provide an upward boost to auto
efficiency in future years, even without new government mandates. The most
important of these is the gasoline direct injection (GDI) engine. These engines
use lean-burn technology and precise fuel control to provide efficiency gains
of 15-20% in typical vehicles. Several manufacturers are now poised to
commercialize GDI technology. However, the lean-burn mode results in much
higher nitrogen oxides (NOX) emissions than conventional engines. Current
emissions control catalyst systems cannot reduce NOX sufficiently due to the
high sulfur level in today's gasoline. Thus, GDI is unlikely to penetrate the
fleet until gasoline sulfur is reduced significantly. The recently proposed
reduction to 30 ppm (average) by 2004 should enable GDI technology to begin to
enter the fleet. As the engines gain consumer acceptance, penetration should
increase rapidly. As a result of GDI and other technological advancements,
average light-duty vehicle fleet efficiency is projected to increase by about
20% from 2005 to the end of the forecast period.
Our forecast of new car efficiency changes results in an EPA based average
fuel efficiency in the year 2010 at about 30.4 MPG's and 34 in 2015 versus
about 28.7 currently. Purvin & Gertz expects new truck efficiencies to gain
modestly as well. When translated to the fleet calculation, they yield about a
21.6 fleet MPG average in 2015 versus about 19.3 currently.
NON-HIGHWAY FUEL USE ADJUSTMENTS
To accurately project gasoline and diesel fuel consumption, the data must be
adjusted to account for the reporting differences between Federal Highway
Administration (FHA) data and Department of Energy (DOE)
C-19
<PAGE>
numbers. The FHA collects consumption numbers on the basis of the federal tax
revenues collected. This is different from the data collected by the DOE, which
include all gasoline supplied for both highway and non-highway use. Diesel and
special fuels consumed for highway use are collected by the FHA. Adjustments
have been made to reflect non-highway use. Also, comparing FHA and DOE growth
rates on a total U.S. basis does not show dramatic differences except where
significant secondary inventory shifts might be effecting the primary demand
data. When comparing rates by PADD, however, the differences can be large,
reflecting transfers between regions. We have developed a correction method
that incorporates this and allows FHA data history and forecasts to be
converted into a DOE basis by PADD.
ALTERNATIVE FUELS
Much discussion and concern recently has focused on the possible effects of
alternative fuels on gasoline demand. Obviously, significant penetration of
non-gasoline vehicles into society would have very important implications for
refiners. Reduced gasoline demand would change the outlook for capacity
requirements. If rapid changes occurred, there could be a negative effect on
industry profitability.
Our analysis still indicates that alternative fuels are not likely to have a
significant effect on gasoline demand until late in the next decade, and the
extent of impact then is by no means a clear issue at this point. The primary
alternative fuels presently at issue include methanol, CNG, LPG, and
electricity. LPG (primarily propane) contributed about 41,000 B/D to the
transportation sector in 1997, and this is projected to grow to about 55,000
B/D by early in the next decade. Though CNG is currently in use, its
application is likely to be restricted to fleet vehicles for some time. Fleet
vehicles, however, represent only a small portion of the overall fleet, and the
effect on gasoline demand, therefore, would likely be small, unless full
conversions were made. A major portion of CNG use is also displacing diesel
fuel rather than gasoline. We also expect methanol usage to be inconsequential,
taking into account such factors as toxicity, logistics and economics.
The West Coast has been a leader in mandating alternative fuels. In 1990, the
California Air Resources Board (CARB) mandated zero emissions or electric
vehicles (ZEV's) to comprise two percent of new vehicle sales by the 1998 model
year increasing to ten percent by 2003. Technological progress has not met the
CARB expectations and only a few hundred ZEV's have been licensed for highway
use in California.
CARB has delayed and modified the ZEV mandate. Due to a failure for auto
manufacturers to produce a viable electric vehicle, mandates for 1998 through
2002 were suspended. Furthermore, the program has been modified to allow for
production of equivalent zero emissions vehicles (EZEV's) which have emissions
profiles similar to the generating stations used to power electric hybrid
electric vehicles (HEV's). The fuels which would power EZEV's or HEV's are not
limited but they could include petroleum-based fuels manufactured in the
California refining system. Future sales of ZEV's and other alternative fuel
variants will depend on the ability of auto manufacturers to devise products
incorporating those emissions characteristics while preserving performance and
value parameters demanded by the auto-buying public.
U.S. GASOLINE DEMAND
Gasoline consumption declined from a high of about 7.4 million B/D in 1978 to
only 6.5 million B/D in 1982, but this decline was reversed as gains in vehicle
miles traveled began to outweigh the mandated fuel efficiency improvements, and
as the fuel standards were relaxed. Because of relatively stable energy prices,
the percentage of disposable income required to pay fuel bills began to shrink
as incomes grew. Consequently, consumers had more money to spend on lifestyle
improvement and they chose to purchase larger, higher-performance automobiles
rather than smaller cars. In combination with increased driving, this caused
gasoline consumption to grow through the early 1980s. The drop in prices in
1986 resulted in a particularly strong increase. However, beginning in 1989,
efficiency improvements outpaced increased driving. The significant impact of
briefly increased prices and the economic downturn in 1990 and 1991 is
particularly evident in the driving trends over that period.
C-20
<PAGE>
Large gains in prices due to the Gulf War caused US motor gasoline demand
growth to drop sharply in the early 1990's. As prices equilibrated from the
highs of the war, demand recovered 2.5% in 1995. In 1996 strong overall
petroleum demand tightened the market causing prices to rise. Counterbalancing
some of the increases in prices were consumer spending increases and as well as
a choice for larger more inefficient sports utility vehicles versus smaller
passenger cars. The price collapse in 1998 elevated demand growth to above 2%.
We continue to see the near term growth around 2% as prices slowly recover. By
2015 motor gasoline demand growth is projected to drop to less than 0.5% which
will result in higher efficiency in the outer years. This forecast evolves on
new vehicle technology.
C-21
<PAGE>
TABLE IV-2
UNITED STATES REFINED PRODUCT BALANCE
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Product Flow 1995 1996 1997 1998 1999 2000 2005 2010 2015
- ------- -------------------- ------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gasoline Production 7,588 7,647 7,870 8,041 8,180 8,330 8,691 9,204 9,454
Gasoline Imports 265 336 309 299 323 322 343 366 380
Gasoline Exports 104 104 137 125 117 128 135 143 148
Gasoline Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Gasoline Supply Adjustments 40 12 (26) (15) 7 (10) (11) (11) (3)
Gasoline Consumption 7,789 7,891 8,017 8,200 8,393 8,514 8,888 9,416 9,683
Kero/Jet Fuel Production 1,468 1,577 1,620 1,598 1,625 1,662 1,850 2,028 2,193
Kero/Jet Fuel Imports 107 112 92 81 102 106 121 135 148
Kero/Jet Fuel Exports 28 50 35 26 24 24 26 27 28
Kero/Jet Fuel Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Kero/Jet Fuel Supply Adjustments 21 1 (13) (2) (2) (2) (6) (6) (6)
Kero/Jet Fuel Consumption 1,568 1,640 1,663 1,651 1,701 1,742 1,940 2,130 2,308
Distillate Production 3,155 3,316 3,392 3,421 3,439 3,557 3,921 4,303 4,670
Distillate Imports 193 230 228 195 216 222 242 263 283
Distillate Exports 183 190 152 124 122 133 120 113 102
Distillate Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Distillate Supply Adjustments 41 10 (32) (49) 17 4 (17) (20) (18)
Distillate Consumption 3,207 3,365 3,435 3,442 3,549 3,650 4,026 4,433 4,833
Residual Fuel Production 788 726 708 762 722 724 696 697 691
Residual Fuel Imports 187 248 194 203 195 196 187 177 171
Residual Fuel Exports 136 102 120 138 114 113 103 112 112
Residual Fuel Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Residual Fuel Supply Adjustments 13 (24) 15 (10) 8 3 1 1 0
Residual Fuel Consumption 852 848 797 817 811 810 781 762 751
Asphalt Production 467 459 485 492 511 526 593 653 706
Asphalt Imports 36 27 32 28 29 29 32 34 35
Asphalt Exports 6 7 8 7 7 8 9 9 10
Asphalt Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Asphalt Supply Adjustments (11) 5 (4) 2 (1) (2) (3) (3) (3)
Asphalt Consumption 486 484 505 515 531 545 613 674 728
Other Production 1,986 1,996 2,128 2,142 2,196 2,226 2,350 2,487 2,521
Other Imports 356 421 448 477 471 466 455 459 473
Other Exports 365 394 412 346 361 367 384 404 415
Other Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Other Supply Adjustments 567 596 587 514 458 464 564 599 652
Other Consumption 2,545 2,620 2,754 2,786 2,761 2,786 2,982 3,138 3,229
Total Production 15,453 15,720 16,202 16,456 16,673 17,025 18,102 19,373 20,235
Total Imports 1,144 1,375 1,303 1,284 1,337 1,342 1,378 1,434 1,491
Total Exports 821 847 864 766 745 773 776 808 815
Total Int'l Marine Bunkers 0 0 0 0 0 0 0 0 0
Total Supply Adjustments 671 600 526 440 486 456 528 559 623
Total Consumption 16,447 16,848 17,171 17,412 17,748 18,047 19,230 20,555 21,532
</TABLE>
C-22
<PAGE>
DIESEL/NO. 2 FUEL OIL
Consumption dropped in 1990 and again in 1991 due to the warm weather,
particularly along the Eastern Seaboard and due to the economic downturn, which
was exacerbated by the crisis in the Middle East. Demand turned up in 1992 and
1993 due to the economic recovery and rose sharply in 1994 (Table IV-2) due to
the severe winter. The unusual weather in 1994 resulted in only modest gains in
1995 for the winter fuels, but the extended cold waves in early 1996 led to a
recovery. Demand growth in 1996 averaged close to 5% with strong gains in
diesel as well as heating oil. In 1997, the winter was significantly milder,
resulting in an increase of only 2%. In 1998 the mild weather caused by El Nino
effects resulted in demand rising only 0.2%.
Distillate fuel oil market growth in the future will come mostly from
increases in transportation consumption. Diesel penetration of the personal
automobile fleet will be negligible. However, continued economic growth will
increase the need for trucking and, therefore, diesel fuel. Bunker use of
distillate has been growing steadily, but should see more moderate increases in
the future. The continued growth in distillate demand will be primarily due to
the rise in transportation demand.
Whereas distillate used for transportation has been growing rapidly, market
shares of distillate in most other sectors have declined. The loss of market
for distillate fuel oil has been particularly noticeable in the residential
sector, Consumption of natural gas and electricity has pushed out demand for
distillate. A strong winter in 1996 revitalized the sector but was quickly gone
with the El Nino effect in 1998. Demand declined 8% to 390 MB/D in 1998. Longer
term, we still expect modest declines in this sector. Consumption of distillate
in the industrial sector (combining industrial, oil company and electric
utility) dropped to about 224,000 B/D in 1997, (the last year for which full
sector information is available). This compares to a high of 460,000 B/D in
1979. The drop has been due to fuel substitution. Consumption in these sectors
has stabilized somewhat since the economy is again growing, but we do not see
foresee major gains in these sectors through the forecast. The use of
distillate fuel oil in the commercial sector also declined through the early
1990s. It has continued to fall to 210,000 in 1997. Consumption in the other
sectors (farm, military, off-highway, and miscellaneous) has also leveled off
in recent years, and only modest growth is anticipated.
In October 1993, refiners began to produce diesel fuel with a much lower
sulfur content from in the on-highway market. These fuels are required to
contain 0.05% sulfur or less. Only about 55% of the distillate pool is required
to meet these more stringent specifications, as it is applicable to on-highway
product. Even so, many refiners are able to produce 100% of lower sulfur
material. Low sulfur diesel is penetrating other sectors, such as farming and
off-highway diesel use, as a result of logistic constraints as well as strong
marketing. In fact, total U.S. low sulfur diesel demand now represents about
66% of distillate use while the on-highway portion is only 56% of total
consumption.
Purvin & Gertz forecasts that low sulfur diesel market share will grow due to
the increasing demand for diesel fuels in the transportation sector, rising to
about 70% of distillate over the next 10 years. This growth in transportation
demands combined with the growth in other sectors will result in low sulfur
demand growing from 2.3 million B/D in 1998 to over 2.4 million B/D by the end
of the decade. Low sulfur diesel growth should exceed 2% annually over the next
decade, but we expect it to taper closer to 2% by the end of the forecast
period. High sulfur distillate demand in contrast remains stagnant, rising from
1.17 million B/D in 1998 to 1.21 million B/D by 2000, and to only 1.35 million
B/D by 2015.
Low sulfur diesel demand has grown more rapidly than expected since its
introduction. This is attributed, at least partially, to use of non-taxable
fuels in this market. This problem now has been alleviated by fuel dyeing for
monitoring purposes.
Most of the distillate fuel oil consumed in this country is produced
domestically, but imports have been averaging about 200,000 B/D under normal
conditions. This material is primarily imported from the Caribbean to the East
Coast, but Canada and Africa are also major supply sources. Due to the somewhat
more robust growth of distillate demand relative to gasoline, refinery
production of distillate relative to gasoline will
C-23
<PAGE>
continue to increase in the future. We also expect imports to remain generally
proportional to demand increases. The introduction of low sulfur diesel fuel
has made it difficult for some exporters to meet these requirements.
Nevertheless, Canada and Virgin Island imports should remain proportional to
demand. In addition, European specifications are being modified to reduce
sulfur levels.
U.S. AVIATION FUELS
Growth in demand for aviation fuels has been one of the strongest among the
refined products, led by commercial kerosene-type jet fuel. Aviation gasoline
usage has held steady over recent years and averages only 20,000 B/D. Military
consumption of naphtha-based jet fuels had been steadily declining due to the
downsizing of the military. The military began the phase-out of JP-4 in 1992
and JP-4 was totally phased out by the end of 1995. This switch substantially
increased the demand for kerosene-based fuels over the phase-out period but the
underlying growth patterns have now become transparent.
Kerosene-type jet fuel demand grew from about 800,000 B/D in the early 1980s
to a peak of 1.34 million B/D in 1990, representing an average growth in excess
of 5%. A decline was noted in 1991 due to the Middle East crisis and the
downturn in the economy, but a strong growth was been evident during the
military switch. Demand in 1997 reached a record high of 1.6 million B/D. The
1998 figures currently indicate a decline, which is inconsistent with other
usage indicators. This is attributed to gross underestimates of imports by the
EIA that we expect to be corrected. Other forecasts take fares into account. We
also expect strong growth to continue throughout the forecast with increasing
airline travel. We are looking for average growth rates in the 2.0-2.5% range
over the next 10 years, declining to about 1.5% by 2015.
The U.S. still produces a major portion of its jet fuel requirements, but
there is some trade. Except during the 1989-1990 Gulf Crisis, net imports have
averaged about 50,000 B/D, with exports ranging from 25,000-40,000 B/D. Most of
the imports come into PADD I, through increases in PADD V are adjusted PADD III
accounts for the bulk of the exports.
U.S. RESIDUAL FUEL OIL
Beginning in the late 1960s, the demand for residual fuel oil began to
escalate rapidly as many of the utility companies burned residual fuel oil in
much greater quantities because of its availability and low cost. In the 1970s,
natural gas was in short supply and residual fuel use was high. The demand for
residual fuel in the utility industry peaked in 1977-1978 at about 1.6 million
B/D, but declined to only 400,000 B/D in 1985. Residual fuel oil demand has
continued to decline and a particularly strong drop occurred in 1995, as gas
availability forced reductions in fuel consumption in Florida and other areas.
The 1995 decline in residual fuel use was 16.6%. Actual sector data is
available through 1997. The data shows utility usage as the major contribution
to the decline. With lower prices relative to natural gas utility demand
strengthened in 1997 and 1998 relative to past years. Purvin & Gertz expects
this trend to reverse again in the forecast.
Another major use of residual fuel oil is in the transportation sector for
vessel bunkering. Consumption in the transportation sector grew rapidly from
260,000 B/D in 1973 to nearly 600,000 B/D in 1980. Much of this growth in
bunker fuel demand was due to U.S. price controls, which caused U.S. bunkers to
be much cheaper than world market prices. Consequently, whenever possible,
foreign ships bunkered in U.S. ports. When crude oil price controls were
lifted, U.S. bunker fuel demand declined to 400,000 B/D. Since that time,
bunker use has fallen to the 315,000 B/D range and appears stabilized at this
level. Increased petroleum imports into the U.S. should cause bunker use to
increase gradually over the forecast period.
The use of residual fuel oil in the industrial sector was 855,000 B/D in
1973, but since then, consumption declined near 120,000 B/D. This level is the
lowest since 1991 when demand was 126,000 B/D. This decline can be attributed
to fuel switching.
Purvin & Gertz expects the decline in utility demand to continue in the years
ahead, however, at a much slower rate. Commercial demand accounts for only a
small portion of total demand and this demand should
C-24
<PAGE>
also fall over the forecast. The declines in utility demand and the small
amount of industrial demand results in the transportation sector's outlook
becoming the dominant determinate on demand for residual fuel oil. Our forecast
anticipates that bunker demand will continue to rise slowly with the growing
amount of international trade. Longer term, this growth, combined with the rise
in industrial demand, will result in residual fuel oil demand declining
slightly on an annual basis during the next decade.
Of the total demand, about 25% is currently being imported. The Caribbean is
the major supply source, but significant, though decreasing, volumes of low
sulfur residual fuel oil are imported from Algeria and Brazil. We expect
imports as a percentage of demand to decline slowly throughout our forecast.
Gulf Coast refiners use the export market to balance their operations. PADD
III has two options: it can either move material to other PADDs or export it.
Since the East Coast primarily uses low sulfur material, excess PADD III high
sulfur material must be exported. Presently, most of these exports are into the
Western Hemisphere blending market and to Caribbean markets such as utilities.
This is a sensitive balance and even slight excesses of supply relative to
regional demand can result in the need to export beyond the Western Hemisphere.
This results in depressed prices in the Gulf Coast, as was seen throughout the
Mideast crisis when refiners were forced to run the higher sulfur heavier
crudes, and early in 1997 when conversion unit problems increased supply. In
1998, export demand increased due to hydropower deficiencies and the market
strengthened. Low production resulting from lighter crude slates and increased
conversion has kept the market strong in 1999.
PADD V satisfies its imbalance from the production of residual fuel oil by
exporting its surplus. This surplus has, however, significantly decreased over
the years and exports have dropped even further as new coking units come
onstream. Total U.S. exports dropped to $100,000 B/D in 1996 from peaks of well
over 200,000 B/D during the Iraqi war when U.S. refiners were running heavier
crudes, and residual fuels had to be exported out of the Western Hemisphere.
they increased to 137,000 B/D in 1998 due to the high export demand. However,
we expect them to drop back to the 100,000 B/D range in the forecast. PADD II
is essentially in balance, but some low sulfur residual fuel oil is moved up
from the Gulf Coast, while small periodic surpluses of high sulfur residual
fuel oil moved down to PADD III. PADD I is the major deficit market in the U.S.
Therefore, it balances its market demand by either importing or transferring
material from PADD III. Generally, PADD III serves the southeastern portion of
PADD I, whereas the foreign product is largely moved to the Northeast market.
U.S. ASPHALT
Asphalt demand in the U.S. is mainly driven by paving requirements for road
construction, resurfacing, restoration, and maintenance. In fact, paving
activities consume nearly 90% of the asphalt demand in most years. Roofing
requirements consume the rest of the demand. The Asphalt Institute conducts an
annual survey of asphalt producers in North America which provides information
on the split between paving and non-paving demand.
Asphalt demand peaked in 1990 at about 485,000 B/D, but dropped off to about
450,000 B/D in 1991/92 as a result of the recession. Demand varies from year to
year, and exceeded 500,000 B/D for the first time in 1997 (Table IV-2). Asphalt
demand is affected by the economy, since roofing asphalt demand is a function
of home building and the replacement market. Paving asphalt demand is dependent
on government funding for road building and repair so it varies with government
policy. Since the outlook for the basic drivers (the economy and
transportation) is positive, we expect asphalt demand to increase over the
forecast period, with normal year to year fluctuations.
The U.S. is basically self-sufficient in asphalt but about 30,000 B/D are
annually imported, primarily from Venezuela. PDVSA is a large producer and
marketer of asphalt in the U.S. and brings in some supplies from Venezuela.
Purvin & Gertz does not expect a significant increase in imports of asphalt.
C-25
<PAGE>
U.S. COKE
Coke consumption has increased along with the increase in production of
marketable coke. In addition to the marketable coke, another 220,000 B/D is
produced and consumed in the refineries. A portion of the coke is low sulfur
and can be used for anodes for the manufacture of aluminum, but most is high
sulfur and is used as fuel or exported. Coke can be used directly for burning
in cement plants and blended with coal for boiler fuel.
PADD II is the largest consumer of coke followed by PADD III. PADD II
consumption, accounts for about 45% of the total usage. There are a number of
coal fueled utility plants in PADD II. The big increase in consumption in PADD
III in 1992 was related to the start-up of a co-generation plant that uses coke
as fuel, but consumption has dropped back off. As more cokers are brought
onstream, coke will be marketed to the extent possible in the U.S., with the
balance exported.
U.S. OTHER PRODUCTS
Production of other products is now about 2.2 million B/D and growing. Most
of these products are consumed in the U.S., but a significant portion of the
coke production is exported, as discussed earlier coke shown in the table below
represents total coke produced. Other product demand has grown very strongly
over the years. In 1997, growth averaged near 3%, rising to 4.7 million B/D.
This includes NGL's and all other non-major fuels products. In 1998, demand
fell to 1996 levels of 4.6 million B/D reflecting mild weather, but we expect
demand to rise by about 1% per year over the forecast.
UNITED STATES OTHER PRODUCT PRODUCTION
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Product 1995 1996 1997 1998 1999 2000 2005 0210 2015
- ------- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Refinery LPG.............. 629 633 664 640 659 667 697 737 756
White Spirits............. 51 50 52 68 69 70 75 79 82
Naphtha................... 172 191 229 244 248 252 270 286 299
Lubes & Waxes............. 196 196 207 208 212 216 233 249 263
Petroleum Coke............ 630 664 690 695 717 727 762 804 775
Miscellaneous............. 308 262 285 287 292 295 314 331 346
Total..................... 1,986 1,996 2,128 2,142 2,196 2,226 2,350 2,487 2,521
</TABLE>
C-26
<PAGE>
V. HEAVY CRUDE OIL AVAILABILITY
There should be adequate supplies of heavy crude available to the Upgrade
Project because heavy crude production is concentrated in the Western
Hemisphere and Purvin & Gertz expects production to increase substantially over
the life of the Upgrade Project. In recent years, heavy crude production has
been increasing rapidly, particularly in Venezuela, Mexico and Canada, whereas
exports to Western Europe and Asian have not increased significantly. The
increased Canadian production has been utilized in refineries in the U.S.
Midwest (PADD II) and Mountain Region (PADD IV). Most of the increase from
Mexico and Venezuela has been placed in refineries on the U.S. Gulf Coast (PADD
III), where the Upgrade Project will be located. Availability of larger
quantities of heavy crude has led to the addition of deep conversion equipment
(such as cokers) to minimize the yield of residual fuel oil in the refining
process. Expected future increases in heavy crude production in Mexico and
Venezuela are causing the heavy oil producers to seek out joint ventures or
crude supply arrangements, such as the Upgrade Project, to process these
crudes. Several others have been announced and more will likely be forthcoming.
HEAVY CRUDE OIL PRODUCTION
Heavy crude production is concentrated in the Western Hemisphere. In 1998,
Latin America produced 3.9 million B/D of heavy crude out of a total worldwide
production of 8.9 million B/D. The U.S. (866,000 B/D) and Canada (825,000 B/D)
contributed 1.7 million B/D, raising the Western Hemisphere total to 5.6
million B/D which represents over 60% of the world's 1998 heavy crude
production. About 2.0 million B/D of heavy crude was produced in the Middle
East, with the balance scattered throughout the rest of world. Heavy crude
production by region is shown in Table V-1 and summarized below.
HEAVY CRUDE PRODUCTION
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Projected
---------------------------------------
1996 1997 1998 1999 2000 2005 2010 2015 2020
----- ----- ----- ----- ----- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
United States........ 915 887 866 857 848 780 696 611 575
Canada............... 682 800 825 799 781 1,201 1,244 1,292 1,292
Latin America........ 3,631 3,899 3,879 3,809 3,837 5,002 5,781 6,473 6,899
Mexico 1,371 1,567 1,607 1,650 1,693 1,910 2,127 2,300 2,417
Venezuela........... 1,985 2,037 1,948 1,817 1,787 2,711 3,251 3,753 4,045
Other............... 275 295 325 342 356 382 404 420 436
Africa............... 331 312 301 291 281 272 254 231 209
Middle East.......... 1,888 1,955 2,034 2,000 2,003 2,251 2,409 2,694 2,751
China................ 691 701 709 718 727 773 807 830 851
Western Europe....... 221 288 302 365 513 557 553 551 550
Eastern Europe....... 28 26 24 23 22 19 16 15 14
Total............... 8,387 8,869 8,940 8,861 9,012 10,855 11,761 12,698 13,140
</TABLE>
Since most of the heavy crude is produced in the Western Hemisphere (Mexico,
Venezuela, and Canada), most is exported to the United States. Exports by
destination for 1998 are shown in the following table.
HEAVY CRUDE EXPORTS: 1998
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
PADD I PADD II PADD III PADD IV PADD V EUROPE ASIA TOTAL
------ ------- -------- ------- ------ ------ ---- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Venezuela............. 164 38 696 -- 18 170 -- 1,086
Mexico................ 22 26 732 -- 22 163 5 970
Canada................ 27 591 4 150 4 -- -- 776
Middle East........... 38 6 286 -- -- 166 222 718
--- --- ----- --- --- --- --- -----
Total................ 251 661 1,718 150 44 499 227 3,550
</TABLE>
C-27
<PAGE>
SUPPLY OF HEAVY CRUDE OIL TO THE UPGRADE PROJECT
The Upgrade Project is being designed to run predominantly Maya crude which
is heavy (22(degrees) API) sour crude. Mexico also produces a medium
(32(degrees) API) sour crude (Isthmus) and a very light (39API) sour crude
(Olmeca).
MEXICAN CRUDE OIL PRODUCTION
Total crude oil and condensate production has increased rapidly since the
first wells in the Chiapas-Tabasco (Reforma) were brought onstream. A high
level of drilling activity in 1978 resulted in production from the prolific
fields in the Bay of Campeche. Total crude oil reserves that were estimated to
be 25.6 billion barrels at the end of 1978 have been officially estimated at
48.8 billion barrels as of January 1, 1998.
Crude production in Mexico increased rapidly from the mid 1970s through the
early 1980s. From 1982 through 1996, production averaged about 2.7 million B/D
and did not reach the 3 million B/D mark until 1997 (Figure V-1 and Table V-2).
Even though total production did not increase significantly over the 1982/98
period, there was a significant shift in quality. Prior to 1982, most of the
production was light sour (Isthmus), but heavy sour (Maya) grew rapidly
starting in 1979, and exceeded 1.0 million B/D in 1982 for the first time. Maya
production has increased slowly since then and was 1.61 million B/D in 1998.
[GRAPHIC OF FIGURE V-1-MEXICO CRUDE PRODUCTION]
C-28
<PAGE>
For the short term, Mexico has agreed to reduce exports to assist the OPEC
producers in reducing excess supplies of crude oil. However, in the longer
term, exports of Maya will increase (Figure V-2).
[GRAPHIC OF FIGURE V-2-MEXICO CRUDE EXPORTS]
In 1988, Mexico began segregating a very light sour crude (Olmeca) and
production of Olmeca peaked at 578,000 B/D in 1996, declining slightly to
554,000 B/D in 1998. At the same time, production of medium sour crude
(Isthmus, 32(degrees)API) declined from about 1.7 million B/D in 1982 to below
900,000 B/D in 1991. Production of Isthmus has remained in the 800,000 to
900,000 B/D range since 1991. Production of Olmeca and Isthmus is forecast to
decline slowly over the next 20 years.
Maya Crude Oil
Most of Mexico's heavy Maya (22(degrees)API and 3.4%S) comes from the
Cantarell field. Within the Cantarell field there are four major fields with
total remaining reserves of 14 billion barrels of crude.
CANTARELL CRUDE OIL RESERVE
(MIllion Barrels)
<TABLE>
<CAPTION>
Original Remaining
-------- ---------
<S> <C> <C>
Akal.................................................. 32,086.4 13,111.2
Chac.................................................. 285.3 33.4
Kutz.................................................. 637.1 363.1
Nohoch................................................ 2,011.1 464.0
Takin................................................. 35.0 14.2
-------- --------
Total............................................... 35,055.3 13,985.9
</TABLE>
PEMEX is initiating a massive nitrogen injection project on the Cantarell
field to boost crude production. Estimated expenditures exceed $1 billion. It
is being brought on in stages, with the first train of the plant (300 MM cfd)
scheduled for April 2000 and the remaining three trains to be onstream by
January 2001. At completion, PEMEX expects production of Maya to increase to
over 2.0 million B/D.
Mexico exports most of its Maya to the U.S., with the balance shipped to
Europe and Asia. While PEMEX prefers to sell its Maya on a term basis, some
Maya could be redistributed between markets. This may take 6 months to 1 year
to accomplish this since PEMEX generally sells its crude on term contracts.
Longer term, PEMEX is likely to have uncommitted volumes of Maya as production
is likely to grow faster than PEMEX can find commitments for its crude.
C-29
<PAGE>
ALTERNATE SOURCES OF HEAVY CRUDE OIL SUPPLY
If for some reason heavy crude from Mexico is not available to the Upgrade
Project, other heavy crudes are likely to be available. Venezuela plans to
increase production of heavy crude and will be looking for outlets for this
production. Venezuela would be a logical place for the Upgrade Project to look
for heavy crude supplies since it would be a short haul crude. Venezuela crudes
are heavier and contain more sulfur than Maya but they can be processed by the
Upgrade Project.
VENEZUELA
Venezuela's reserves are predominantly composed of heavy grade crudes. In
1998, PDVSA had about 75 billion barrels of proved oil reserves, which includes
both developed and undeveloped reserves. Developed reserves totaled 17 billion
barrels in 1998 of which heavy and extra heavy (less than 10API) crudes
comprised approximately 6.5 billion barrels.
Venezuela has a broad range of crude oil produced from numerous fields. Such
production is categorized by Venezuela into three types:
<TABLE>
<S> <C>
Light: 30(degrees)API
Medium: 22-30(degrees)API
Heavy: <22(degrees)API
</TABLE>
Production of the light grade crude oil has been increasing rapidly in recent
years due to the market preference for lighter crudes at rates disproportionate
to reserves.
The medium grade crude classification by PDVSA includes crude predominantly
in the 22-25(degrees)API range, and includes the major 24(degrees)API export
grades. These Venezuelan crudes have somewhat better distillation yields, lower
sulfur content and lower viscosity when compared to most other exported heavy
crude oils. The low gravity is exaggerated by the naphthenic quality of the
crude, although the metals content is typical of Western Hemisphere heavy
crudes.
The heavier than 22(degrees)API crudes include Bachaquero light types of
approximately 17(degrees)API, the Bachaquero heavy types of approximately
13(degrees)API, the Merey crude oil (16(degrees)API and the even heavier types
such as the Boscan 11(degrees)API crude.
In order to more rapidly develop its heavy oil reserves in the Orinoco belt,
Venezuela is developing a number of heavy oil projects. These projects vary in
size from 100,000 to 200,000 B/D, and employ different technologies to produce
syncrudes ranging from light sweet (31(degrees)API) to fairly heavy sour
syncrude (15(degrees)API). These projects currently include the following:
. Conoco has entered in a joint venture with PDVSA (Petrozuata) to upgrade
120,000 B/D of Zuata heavy crude oil (10(degrees)API, 2.7%S) to 104,000
B/D of 20(degrees) to 23(degrees)API high sulfur (2.3%S) syncrude.
. Mobil/Veba entered in a joint venture with PDVSA (Cerro Negro), approved
in October 1997, to upgrade 120,000 B/D of Cerro Negro heavy crude oil
(8(degrees)API) which will be upgraded further at Mobil's Chatmette, LA
refinery and in Veba's European refinery system.
. Total/Statoil (Sincor) entered in a joint venture with PDVSA to upgrade
192,000 B/D of heavy crude oil (9(degrees)API, 3.4%S) to light sweet
syncrude.
C-30
<PAGE>
. Arco/Phillips/Texaco have entered in a $2.2 billion joint venture
Association Agreement with PDVSA (Petrolera Ameriven). In connection with
this project, about 200,000 B/D of Hamaca heavy crude oil (9(degrees)API)
will be upgraded to 180,000 B/D of 25(degrees)API syncrude. This project
is currently on hold pending developments in the energy and capital
markets. Arco recently sold its interest in the project to Phillips and
the new partners plan to start construction by mid 2000.
Venezuela's actual and estimated crude oil production exports and domestic
use is shown in Table V-3. Venezuela's crude oil production declined from the
early 1970s through the late 1980s to 1.56 million B/D. However, since 1986/87,
this trend has reversed and production has doubled to about 3.25 million B/D in
1997 (Figure V-3). Production was down slightly in 1998 and will decrease again
in 1999 as a result of Venezuela's agreement with OPEC to cut production. Prior
to the recent decline in demand, which prompted the cutbacks by OPEC, Venezuela
had announced plans to increase production to 5.5 million B/D by 2008. However,
given the OPEC cutbacks, decline in demand and other developments, reaching
this targeted production rate will likely be delayed.
[GRAPHIC OF V-3-VENEZUELA CRUDE PRODUCTION]
In 1998, PDVSA processed for domestic use mostly medium crude (412,000 B/D)
and light crude (426,000 B/D) in its refineries. Only about 228,000 B/D of
heavy crude was processed. As a result, the majority of heavy crude produced is
exported for processing outside of Venezuela. Exports in 1998 amounted to
approximately 813,000 B/D, 798,000 B/D, and 445,000 B/D of heavy, medium and
light crude oil, respectively (Figure V-4). Since we expect heavy crude
production to increase in line with, or slightly faster than the other grades,
we believe that heavy crude exports will increase. Medium Venezuelan crude also
includes heavy crude ranging from 21(degrees) API to 30(degrees) API with most
of the production being of heavier grades.
[GRAPHIC OF V-4-VENEZUELA CRUDE EXPORTS]
C-31
<PAGE>
Since 1989, Venezuela's crude production has gradually shifted to a higher
percentage of heavy sour crude. Heavy crude accounted for about 22% in 1990,
about 33% in 1997 and is forecast to be about 35% by 2020 (Table V-3).
HEAVY CRUDE BALANCES
Heavy crude production, indigenous consumption, and exports by destination
were analyzed for the historical period of 1990 to 1998 and forecasts were
prepared for 1999 to 2020. The major export markets for heavy crude are shown
in the following table:
MAJOR EXPORT MARKETS FOR HEAVY CRUDE
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Projected
-----------------------------------
1995 1996 1997 1998 1999 2000 2005 2010 2015 2020
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
United States...... 2,335 2,494 2,818 2,885 2,912 3,153 4,367 4,923 5,393 5,500
Canada............. 104 74 79 79 95 96 103 110 118 125
Latin America...... 55 61 86 87 89 90 97 104 111 120
Middle East........ 108 98 80 80 79 79 78 76 75 75
Japan.............. 351 338 343 357 371 386 457 529 550 600
Asia............... 13 15 33 35 35 35 35 35 35 35
Western Europe..... 579 540 541 527 518 506 447 383 315 300
Total............. 3,543 3,620 3,981 4,050 4,099 4,345 5,584 6,160 6,597 6,755
</TABLE>
Worldwide heavy crude production declined from a peak of 7.3 million B/D in
1981 to 6.0 million B/D in 1985, but reached a new high of 8.94 million B/D in
1998 (Table V-1). The output of heavy crude in the Middle East during that time
period was highly influenced by the level of production in Saudi Arabia and the
mix of crude oil grades. The decrease in Middle East heavy crude production in
the 1980s was due to a number of factors, including overall market demand, the
OPEC quota system, and Saudi Arabia's election to have its production efforts
focused on light and medium crudes. Also, as Venezuela strived to maximize
light production within its OPEC quota, its heavy crude output declined through
1989 (Table V-3). OPEC producers capable of producing multiple grades of crude
oil have an incentive to maximize revenues in periods of constrained production
by maximizing production of more profitable light and medium crudes while
making production cuts in the heavy crude oils. Saudi Arabia and Venezuela
increased their share of total production in 1990-91 in connection with the
Gulf War.
During the early 1980s, the higher value of Middle Eastern crudes in other
markets prevented heavy crudes from penetrating the U.S. market. About 65% of
the U.S. heavy crude refining capacity was designed for the low-metals Middle
Eastern crudes and, hence was under-utilized in the early 1980s due to the
price disparity.
Netback pricing arrangements eliminated the disparity and Middle Eastern
imports began flowing into U.S. markets in the late 1980s. Imports of heavy
crude from the Middle East averaged only 24,000 B/D in 1986, but rose rapidly
and peaked at 500,000 B/D in 1991/92. Imports dropped back off during the
1993/97 period. Middle East imports have increased the past two years, with
330,000 B/D of heavy sour crude imported into the U.S. in 1998.
Heavy crude imports from sources other than the Middle East increased
throughout the 1980s and early 1990s. Imports of Maya increased to the 800,000
B/D range, while Venezuelan shipments increased from approximately 300,000 B/D
in 1985 to 900,000 B/D in 1998. Venezuelan exports to the U.S. were stimulated
in part by Venezuelan equity ownership of U.S. heavy crude refining assets.
Canadian exports, mostly to the Midwest, averaged about 400,000 B/D during the
1990-95 period, but surged to over 724,000 B/D in 1998 when more pipeline
capacity became available.
Europe and Japan are the only other major importers of heavy crude.
Consumption in Japan has remained relatively constant for the last several
years. Japan imports 350,000-375,000 B/D, mostly from the Middle East.
C-32
<PAGE>
Imports of heavy crude into Europe are declining. From a peak of 875,000 B/D in
1992, imports declined to approximately 527,000 B/D in 1998. Most of Europe's
imports come from Latin America and the Middle East, but Egypt exports about
50,000 B/D to southern Europe.
Over the next several years production of heavy crude will not increase as
rapidly as in the recent past. The OPEC cutbacks will cause less heavy crude to
be produced in Venezuela and in the Middle East. Canada's plans to increase
heavy oil production have also been slowed by the recent crude price drop.
However, the crude price is already recovering so the impact of the price
drop will be short live. As is illustrated in the following table, we expect
heavy crude production to further increase during the 2000 to 2020 period with
the major production increases occurring in the following areas.
MAJOR HEAVY CRUDE OIL PRODUCTION INCREASES
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Production Production Increases
------------------------------------------------- ------------------------
Projected
------------------------------- 1998 2000- 2010- 2015-
1985 1990 1998 2000 2005 2010 2015 2020 2000 2010 2015 2020
----- ----- ----- ----- ----- ----- ------ ------ ---- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
California OCS 81 82 131 123 86 60 43 40 (8) (63) (18) (2)
Canadian................ 297 449 825 781 1,201 1,244 1,292 1,292 (44) 462 48 0
Mexico.................. 1,126 1,223 1,607 1,693 1,910 2,127 2,300 2,417 87 433 173 117
Venezuela............... 1,088 1,202 1,948 1,787 2,711 3,251 3,753 4,045 (160) 1,463 502 292
Middle East............. 966 1,662 2,034 2,003 2,251 2,409 2,694 2,751 (31) 407 285 57
Total................. 3,559 4,618 6,544 6,388 8,159 9,091 10,081 10,546 (156) 2,703 991 464
</TABLE>
C-33
<PAGE>
TABLE V-1
WORLD CRUDE OIL PRODUCTION BY REGION AND TYPE
(Thousands Barrels per Day)
<TABLE>
<CAPTION>
Projected
-----------------------------------------
1995 1996 1997 1998 1999 2000 2005 2010 2015 2020
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
United States
Condensate............. 357 383 396 420 437 456 416 371 329 293
Light Sweet............ 2,584 2,536 2,487 2,455 2,426 2,408 2,290 2,088 1,897 1,739
Light Sour............. 2,730 2,722 2,755 2,675 2,767 2,848 2,963 2,882 2,635 2,323
Heavy Sour............. 939 915 887 865 857 848 780 696 611 575
Total.................. 6,610 6,557 6,525 6,415 6,485 6,560 6,449 6,037 5,473 4,930
Canada
Condensate............. 163 175 177 189 200 206 238 256 268 276
Light Sweet............ 896 876 851 910 933 966 1,316 1,374 1,349 1,379
Light Sour............. 284 274 285 280 275 272 245 219 196 176
Heavy Sour............. 615 682 800 825 799 781 1,201 1,244 1,292 1,292
Total.................. 1,958 2,007 2,114 2,204 2,207 2,225 3,000 3,093 3,105 3,123
Latin America
Condensate............. 36 38 41 43 44 45 53 59 63 66
Light Sweet............ 990 1,210 1,355 1,519 1,658 1,788 2,000 2,180 2,323 2,462
Light Sour............. 3,910 4,101 4,091 4,032 3,904 3,815 4,492 6,147 5,626 6,056
Heavy Sour............. 3,218 3,631 3,899 3,879 3,809 3,837 5,002 5,781 6,473 6,899
Total.................. 8,153 8,981 9,386 9,473 9,416 9,485 11,548 13,167 14,484 15,482
Middle East
Condensate............. 15 19 23 27 31 34 36 37 38 39
Light Sweet............ 485 533 571 817 813 808 820 833 843 852
Light Sour............. 16,464 16,643 17,170 16,049 17,887 17,882 20,526 22,647 26,337 27,066
Heavy Sour............. 1,821 1,888 1,955 2,034 2,000 2,003 2,251 2,409 2,694 2,751
Total.................. 18,786 19,083 19,719 20,926 20,730 20,727 23,633 25,927 29,912 30,707
Africa
Condensate............. 92 93 94 103 96 95 109 118 128 131
Light Sweet............ 5,244 5,449 5,568 5,787 5,656 5,669 6,510 7,136 7,762 8,071
Light Sour............. 604 600 588 587 588 590 568 532 487 445
Heavy Sour............. 352 331 312 301 291 281 272 254 231 209
Total.................. 6,292 6,474 6,583 6,778 6,631 6,634 7,458 8,040 8,608 8,855
Asia
Condensate............. 51 57 64 65 66 67 64 62 61 60
Light Sweet............ 3,516 3,544 3,574 3,600 3,602 3,587 3,588 3,634 3,690 3,655
Light Sour............. 80 80 87 88 88 88 86 84 82 81
Heavy Sour............. 0 0 0 0 0 0 0 0 0 0
Total.................. 3,647 3,681 3,726 3,753 3,755 3,741 3,738 3,780 3,833 3,796
China
Condensate............. 0 0 0 0 0 0 0 0 0 0
Light Sweet............ 2,330 2,450 2,487 2,515 2,545 2,576 2,740 2,852 2,944 3,018
Light Sour............. 0 0 0 0 0 0 0 0 0 0
Heavy Sour............. 657 691 701 709 718 727 773 807 830 851
Total.................. 2,987 3,141 3,188 3,225 3,263 3,303 3,513 3,670 3,774 3,870
</TABLE>
C-34
<PAGE>
TABLE V-1--(Continued)
WORLD CRUDE OIL PRODUCTION BY REGION AND TYPE
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Projected
-----------------------------------------
1995 1996 1997 1998 1999 2000 2005 2010 2015 2020
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Western Europe
Condensate............. 99 111 111 109 125 130 93 89 83 78
Light Sweet............ 5,311 5,646 5,544 5,473 6,023 6,291 5,510 6,053 5,298 4,461
Light Sour............. 379 373 364 366 400 405 308 280 241 213
Heavy Sour............. 151 221 288 302 365 513 557 553 551 550
Total.................. 5,940 6,351 6,307 6,251 6,914 7,339 6,467 6,974 6,174 5,301
Eastern Europe
Condensate............. 31 30 26 25 24 23 20 17 16 15
Light Sweet............ 164 162 160 159 158 156 145 137 131 126
Light Sour............. 34 33 31 30 29 26 25 23 21 20
Heavy Sour............. 29 28 26 24 23 22 19 16 15 14
Total.................. 257 253 243 238 234 229 208 194 184 175
FSU
Condensate............. 318 317 336 334 338 340 354 389 447 580
Light Sweet............ 175 174 173 173 221 233 290 970 1,460 3,645
Light Sour............. 6,673 6,576 6,720 6,684 6,682 6,677 6,845 7,235 7,999 9,174
Heavy Sour............. 0 0 0 0 0 0 0 0 0 0
Total.................. 7,166 7,067 7,228 7,191 7,241 7,249 7,488 8,594 9,906 13,398
Total World
Condensate............. 1,162 1,224 1,267 1,312 1,359 1,396 1,382 1,398 1,432 1,537
Light Sweet............ 21,694 22,581 22,771 23,409 24,035 24,480 25,209 27,268 27,697 29,407
Light Sour............. 31,157 31,403 32,093 32,792 32,620 32,604 36,057 39,048 43,626 45,553
Heavy Sour............. 7,782 8,387 8,869 8,941 8,861 9,012 10,855 11,761 12,698 13,141
Total.................. 61,795 63,595 65,000 66,453 66,875 67,492 75,503 79,476 85,453 89,637
</TABLE>
C-35
<PAGE>
TABLE V-2
MEXICAN CRUDE OIL BALANCES
(Thousands of Barrels Per Day)
<TABLE>
<CAPTION>
Production Exports Domestic Use
-------------------------- -------------------------- -------------------------
Maya Isthmus Olmeca Total Maya Isthmus Olmeca Total Maya Isthmus Olmeca Total Runs Draw
----- ------- ------ ----- ----- ------- ------ ----- ---- ------- ------ ----- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1976 0 801 0 801 0 94 0 94 0 707 0 707
1977 0 981 0 981 0 202 0 202 0 779 0 779
1978 0 1,213 0 1,213 0 365 0 365 0 848 0 848 828 (20)
1979 12 1,459 0 1,471 12 521 0 533 0 938 0 938 890 (48)
1980 611 1,325 0 1,938 370 458 0 828 241 867 0 1,108 1,054 (54)
1981 887 1,426 0 2,313 611 487 0 1,098 276 939 0 1,215 1,174 (41)
1982 1,041 1,706 0 2,747 812 679 0 1,491 229 1,027 0 1,258 1,161 (95)
1983 1,117 1,548 0 2,665 859 678 0 1,537 258 870 0 1,128 1,122 (6)
1984 1,178 1,506 0 2,884 904 540 0 1,444 274 966 0 1,240 1,224 (16)
1985 1,126 1,505 0 2,630 832 606 0 1,438 294 898 0 1,192 1,246 54
1986 1,025 1,402 0 2,426 836 452 0 1,290 187 950 0 1,137 1,214 76
1987 1,178 1,363 0 2,541 819 526 0 1,345 359 837 0 1,196 1,256 60
1988 1,163 1,272 72 2,507 768 457 72 1,307 395 805 0 1,200 1,245 45
1989 1,188 1,178 148 2,513 788 344 148 1,278 402 834 0 1,236 1,288 52
1990 1,223 1,167 158 2,548 827 293 158 1,277 396 874 0 1,271 1,307 36
1991 1,328 917 431 2,676 875 328 162 1,365 453 589 269 1,311 1,345 34
1992 1,348 892 430 2,668 935 291 160 1,386 411 601 270 1,282 1,335 53
1993 1,320 791 562 2,673 861 264 220 1,345 459 527 342 1,328 1,370 42
1994 1,270 890 525 2,665 806 179 329 1,314 464 711 196 1,371 1,413 42
1995 1,220 864 533 2,617 721 158 432 1,311 499 706 101 1,306 1,349 43
1996 1,371 910 578 2,859 866 192 495 1,553 505 718 83 1,306 1,353 47
1997 1,567 881 574 3,022 1,020 216 485 1,721 547 665 89 1,301 1,243 (58)
1998 1,607 900 554 3,060 1,084 197 473 1,754 523 703 81 1,306 1,287 (19)
Projected
1999 1,650 898 550 3,098 1,111 230 463 1,803 539 669 88 12,95 1,295 0
2000 1,693 894 547 3,134 1,138 226 452 1,816 555 669 95 1,319 1,319 0
2001 1,737 888 544 3,166 1,165 219 442 1,826 572 669 102 1,343 1,343 0
2002 1,780 879 540 3,200 1,192 209 432 1,832 588 671 109 1,367 1,367 0
2003 1,823 869 537 3,229 1,219 197 421 1,837 504 672 116 1,392 1,392 0
2004 1,867 859 533 3,259 1,246 186 411 1,842 621 673 123 1,416 1,416 0
2005 1,910 849 530 3,289 1,273 175 400 1,848 837 674 130 1,441 1,441 0
2006 1,953 840 527 3,320 1,300 164 390 1,854 853 676 137 1,466 1,466 0
2007 1,997 831 523 3,351 1,327 154 380 1,661 870 677 144 1,491 1,491 0
2008 2,040 823 520 3,383 1,354 144 369 1,868 686 679 151 1,516 1,516 0
2009 2,083 814 517 3,414 1,381 134 359 1,874 702 680 158 1,540 1,540 0
2010 2,127 804 513 3,444 1,408 122 349 1,878 718 682 165 1,565 1,565 0
2015 2,300 618 500 3,616 1,500 128 300 1,928 800 691 200 1,691 1,691 0
2020 2,417 860 526 3,803 1,617 44 326 1,986 800 816 200 1,816 1,816 0
</TABLE>
C-36
<PAGE>
TABLE V-3
VENEZUELAN CRUDE OIL BALANCES
(Thousands Barrels Per Day)
<TABLE>
<CAPTION>
Domestic Use
Production Exports (Includes Inventory changes)
----------------------------- ----------------------------------- -----------------------------------
Recon-
Hvy Med Light Cond. Total Hvy Med Light(1) stituted Total Hvy Med Light Cond. Total Runs
----- ----- ----- ----- ----- ----- ----- -------- -------- ----- ----- ----- ------ ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1976 617 876 787 20 2,294 379 406 424 171 1,360 238 469 378 0 11,085 987
1977 678 782 779 18 2,236 461 303 346 170 1,330 227 399 452 0 1,076 970
1978 667 759 720 20 2,106 421 347 269 179 1,216 246 412 471 0 1,129 838
1979 790 830 718 21 2,358 508 413 274 159 1,444 192 417 462 0 1,071 982
1980 803 693 630 21 2,147 635 292 220 130 1,283 168 401 428 0 994 692
1981 830 639 600 19 2,088 660 312 212 64 1,267 171 327 407 0 905 840
1982 735 582 582 17 1,876 876 227 186 74 1,082 160 336 393 0 886 843
1983 745 451 534 33 1,763 588 188 123 86 986 157 263 444 0 864 842
1984 798 322 351 108 1,690 723 101 117 67 824 82 393 333 0 808 839
1985 808 480 351 119 1,658 626 87 137 74 824 82 393 333 0 808 867
1986 472 653 378 142 1,645 489 156 254 50 949 (17) 497 266 0 746 867
1987 410 589 370 166 1,534 470 212 296 48 1,026 (60) 377 237 0 554 807
1988 303 708 428 168 1,716 467 196 311 47 1,010 (64) 513 303 0 782 938
1989 313 827 448 160 1,748 332 185 417 62 986 (19) 642 191 0 814 907
1990 456 880 700 61 2,086 491 348 355 48 1,242 (37) 532 396 0 891 917
1991 622 999 680 37 2,338 592 432 299 59 1,382 30 567 418 0 1,016 1,014
1992 621 989 687 37 2,334 648 478 257 47 1,429 (28) 513 467 0 952 941
1993 728 871 692 35 2,326 663 658 270 49 1,540 65 313 467 0 835 950
1994 922 1,047 669 40 2,588 712 651 274 57 1,693 211 396 326 0 932 935
1995 915 1.098 710 39 2,760 696 691 405 26 1,618 219 405 344 0 968 1,004
1996 1,048 1,242 816 48 3,154 826 835 474 50 2,185 222 407 300 0 1,019 1,019
1997 1,082 1,269 848 61 3,250 887 860 479 60 2,246 226 409 420 0 1,054 1,054
1998 1,041 1,209 817 56 3,122 813 798 402 60 2,106 228 412 426 0 1,086 1,086
Projected
1999 977 1,124 774 60 2,925 747 710 402 50 1,909 230 414 423 0 1,067 1,067
2000 987 1,101 705 57 2,890 734 685 402 50 1,871 233 416 420 0 1,069 1,069
2001 1,058 1,189 847 57 3,140 920 771 486 50 2,127 236 418 418 0 1,072 1,072
2002 1,137 1,267 926 60 3,385 898 847 505 50 2,380 239 421 416 0 1,078 1,075
2003 1,346 1,485 1,118 51 4,000 1,104 1,062 756 50 2,972 242 423 413 0 1,078 1,078
2004 1,438 1,670 1,208 60 4,266 1,194 1,145 847 50 3,235 244 425 411 0 1,081 1,081
2005 1,514 1,635 1,284 60 4,483 1,267 1,207 922 50 3,446 247 427 412 0 1,088 1,088
2006 1,686 1,694 1,355 51 4,687 1,336 1,264 1,000 50 3,650 250 430 407 0 1,086 1,086
2007 1,658 1,751 1,426 53 4,887 1,404 1,319 1,075 50 3,848 253 432 404 0 1,089 1,089
2008 1,728 1,806 1,495 55 5,084 1,471 1,371 1,151 50 4,042 265 434 402 0 1,082 1,082
2009 1,797 1,858 1,573 54 5,282 1,530 1,422 1,228 50 4,238 268 430 400 0 1,094 1,094
2010 1,874 1,917 1,658 50 5,500 1,613 1,478 1,311 50 4,453 261 439 397 0 1,097 1,097
2015 2,235 2,160 2,049 60 6,500 1,960 1,710 1,720 50 5,440 275 450 385 0 1,110 1,110
2020 2,490 2,269 2,301 117 7,177 2,190 1,769 2,095 50 6,104 300 500 323 0 1,123 1,123
</TABLE>
- -------
Notes: (1) includes Condensate
C-37
<PAGE>
TABLE V-4
TOTAL UNITED STATES HEAVY SOUR CRUDE OIL SUPPLY/DEMAND
(Thousand Barrels Per Day)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total Runs.............. 13,972 14,195 14,662 14,837 15,003 15,253 16,370 17,393 18,205
Heavy Sour Runs......... 3,136 3,293 3,628 3,708 3,762 3,994 5,141 5,614 6,000
% Heavy Sour Runs....... 22 23 25 25 25 26 31 32 33
Production.............. 939 916 887 866 857 848 780 696 611
Imports
Africa................. 30 35 34 30 30 30 30 30 30
Asia................... 0 0 0 0 0 0 0 0 0
Canada................. 509 554 705 724 694 670 960 1,026 1,096
China.................. 0 0 0 0 0 0 0 0 0
Eastern Europe......... 0 0 0 0 0 0 0 0 0
FSU.................... 0 0 0 0 0 0 0 0 0
Japan.................. 0 0 0 0 0 0 0 0 0
Latin America.......... 1,526 1,649 1,804 1,740 1,845 2,122 3,105 3,655 4,114
Middle East............ 138 147 181 330 316 303 235 168 100
United States.......... 131 109 75 40 5 5 4 4 3
Western Europe......... 1 0 18 20 22 24 32 41 50
Subtotal Imports....... 2,335 2,494 2,818 2,885 2,912 3,153 4,367 4,923 5,393
Exports
Africa................. 0 0 0 0 0 0 0 0 0
Asia................... 0 0 0 0 0 0 0 0 0
Canada................. 0 0 0 0 0 0 0 0 0
China.................. 0 0 0 0 0 0 0 0 0
Eastern Europe......... 0 0 0 0 0 0 0 0 0
FSU.................... 0 0 0 0 0 0 0 0 0
Japan.................. 0 0 0 0 0 0 0 0 0
Latin America.......... 0 0 0 0 0 0 0 0 0
Middle East............ 0 0 0 0 0 0 0 0 0
United States.......... 131 109 75 40 5 5 4 4 3
Western Europe......... 0 0 0 0 0 0 0 0 0
Subtotal Exports....... 131 109 75 40 5 5 4 4 3
Total Supply............ 3,143 3,300 3,630 3,710 3,764 3,996 5,143 5,616 6,001
</TABLE>
C-38
<PAGE>
VI. DIVERSION RISKS
There is always some risk that crude from a particular source will be
disrupted or diverted from a particular market for any number of reasons:
. Weather or other "force majeure."
. Infrastructure constraints.
. Political interference.
. Production changes.
. Marketing opportunities.
The risks can be minimized by designing in flexibility to use crude from
alternative sources. Usually, weather related disruptions are short lived.
Similarly, infrastructure constraints like pipeline bottlenecks, etc., can be
relieved fairly quickly. Political interference like the Iraqi, Libyan, or
Iranian embargoes, last longer and can sometimes be permanent. Decline in
production or better marketing opportunities can also be more permanent and
structural impediments are generally long lasting.
PRODUCTION CHANGES
Declines in production can often be anticipated but, if not, the gradual
nature of full decline provides time to make alternative arrangements. The
Upgrade Project is being designed to run Maya crude. Generally, it is risky to
design a facility capable of running only one specific crude particularly if
the design crude has a unique set of characteristics. The field could decline,
the producer could refuse or be unable to deliver, etc. However, in this case,
the risks are reduced since Mexico has a very active program underway to
significantly expand Maya production. In addition, Venezuela is also expanding
its heavy crude production as well. However, a facility designed to handle Maya
crude (22API) can easily substitute other heavy crudes like Neutral Zone crudes
or many Venezuelan crudes since they are generally lighter and have less metals
and sulfur.
MARKETING OPPORTUNITIES
Producers continuously analyze market opportunities to seek out the highest
possible netbacks consistent with maximizing production and hence revenue. Even
so, most crude today is sold under contract so that efficient transportation
arrangements can be made and crude will flow regularly from producer to
consumer. In this environment, crudes tend to flow to the highest value market
and the flow patterns are fairly stable. Stability is often disrupted by sudden
increases (decreases) in supply in a producing region. For example, the rapid
increase in crude supplies in the Atlantic Basin (North Sea, West Africa, Latin
America) is causing flow pattern changes.
In recent years, Mexico, Venezuela and Canada have increased production of
heavy crude and have placed as much as possible in the U.S. (particularly in
the U.S. Gulf Coast). These crudes have reduced requirements for crude from the
Middle East. Mexico and Venezuela have a strong incentive to place the crude in
the U.S. because other markets are much farther away so the shipping cost would
reduce the netbacks to the producers. Furthermore, the refining industry in
most other regions is not configured to handle heavy sour crude. In 1997, PEMEX
exported 843,000 B/D of Maya to the U.S. which accounts for 84% of its heavy
exports.
Northwest Europe, for example, has a large surplus of light sweet crude
coming out of the North Sea. Refineries in this region have no incentive to
invest to run heavy crude when more than adequate supplies of light sweet crude
are available. In addition, the requirement for low sulfur products and the
availability of natural gas from the North Sea and Russia reduces the need for
residual fuel oil, particularly high sulfur resid. Heavy sour crudes yield a
much larger percentage of high sulfur resid than light sweet crude.
C-39
<PAGE>
Refineries in the Mediterranean region were designed to handle some heavy
sour crude from the Middle East. However, a similar requirement for low sulfur
fuels is reducing the demand for crudes which yield high sulfur resid. Declines
in resid consumption is being expedited by the significant increases in
availability of natural gas from Africa, Russia and the North Sea.
Asia is choosing lighter crudes from Africa and the Middle East for similar
reasons. Product specifications are requiring lower sulfur products and
refiners are better able to meet these requirements by selecting lighter crudes
and minimizing investments. Japan is the major market for heavy crude as their
refineries were configured to handle heavy crudes from the Middle East. Even
so, Japan is resisting pressure from Middle East producers to use more heavy
crude.
The small quantities of heavy crude from Mexico and Venezuela that are
exported to Europe and Asia are primarily for asphalt manufacture. These crudes
make good asphalt and are highly sought for these properties. However, the
quantities are limited and growth in demand will be moderate. Most of Mexico's
shipments to Europe go to Spain under a state to state arrangement between
PEMEX and Repsol of Spain with smaller quantities going to Portugal. Most of
Venezuela's heavy crude shipments to Europe go to Germany where PDVSA has
ownership in a refinery.
U.S. CRUDE OIL IMPORTS
Table VI-1 summarizes total PADD I, II, and III heavy sour crude oil imports
for 1994 through 1998. The tables demonstrates that the Gulf Coast (PADD III)
is the largest U.S. sour crude oil and heavy sour crude oil import market. The
table also illustrates that PEMEX's market share for crude oil and heavy sour
crude oil in particular is substantial, particularly in the Gulf Coast region.
In the Midwest region (PADD II), where Canadian crude oil has a significant
transportation advantage over Mexican crude oil, PEMEX's market share is small.
PEMEX was the second largest supplier of heavy crude oil to the United States
with a 29% share of imports into the combined U.S. East Coast (PADD I), U.S.
Midwest (PADD II) and U.S. Gulf Coast (PADD III) regional markets in 1998.
Venezuela was first with a 33% share. The PADD (Petroleum Administration for
Defense District) designation is the terminology used to define the various
crude oil refining and marketing regions of the United States. The U.S. Rocky
Mountain (PADD IV) region and the U.S. West Coast (PADD V) region are not
considered competitive markets for Mexican crude oil due to logistical and
competitive advantages possessed by Californian and Alaskan production.
Sour crude imports for 1996 through 1998 by source are shown in Table VI-2.
Crude runs by refinery for 1996 and 1997 are shown in Tables VI-3 and VI-4,
respectively.
MAJOR CUSTOMERS
PEMEX's high U.S. market share is a result of increasing availability of
heavy sour crude and its proximity to the market, as well as an effective
marketing strategy. PEMEX is entering into agreements with refineries capable
of efficiently processing heavy sour crude oil. The first joint venture coker
project was with Shell at Deer Park. In late 1996, a 60,000 B/D coker came
onstream. An announcement has been made that the coker will be expanded and
Maya crude runs will be increased at Deer Park. PEMEX has also entered into a
100,000 B/D crude supply agreement with Coastal for Aruba. Purvin & Gertz
expects about 220,000 B/D of Maya crude to be run when the new coker is
completed in 2000. The Upgrade Project at the Clark Port Arthur refinery calls
for about 200,000 B/D of Maya to be run at this facility. Recently agreements
have been reached with Exxon to increase Maya runs to 65,000 B/D when the coker
is expanded at Baytown and with Marathon to run 90,000 B/D when its new coker
is completed. Long term contracts for Maya for 2002 now total 675,000 B/D.
Table VI-5 lists the primary customers for PEMEX in the U.S. ranked by total
barrels of heavy crude oil imported into PADDs I, II, and III over the 1994-98
period. As the table illustrates, customers of PEMEX together represented
around 800,000 B/D of the heavy crude oil imports into the U.S. in 1998 and
this will increase in the future.
C-40
<PAGE>
STRUCTURAL IMPEDIMENTS
Structural constraints which would reduce the risks of diversion can either
be physical (i.e. the refinery design does not allow heavy sour crude to be
run), ownership (for example, Venezuelan crude will be selected over Maya if
unable to run in refineries owned by PDVSA) or geographical (such as Canadian
heavy can more easily capture markets in the Northern Tier markets whereas Maya
can compete more effectively on the U.S. Gulf Coast.
PHYSICAL LIMITATIONS
As shown in Table VI-3, about 3.9 million B/D or 43% of the refinery capacity
in PADDs I-III is designed for light sweet. This excludes this capacity from
consideration. Another 2.9 million B/D or 32% of the refinery capacity is
designed for light sour. Light sour refiners can run some heavy sour but they
probably have already heavied up their slate to the extent possible. Therefore,
about 75% of the refinery capacity can be excluded as a potential market for
Maya or other heavy crude.
OWNERSHIP LIMITATIONS
PDVSA's equity ownership of more than 900,000 B/D of refining capacity, its
substantial import market share among existing third party refineries capable
of processing Venezuelan type crude oil, and the discounts that would be needed
to increase market share in existing complex refineries or through additions of
new capacity effectively limit the possibility of a major shift by PEMEX away
from supplying their contracted customers. Should PEMEX attempt such a shift,
the resulting competition for the sale of heavy crude oil could result in a
downward spiral of retaliatory price discounting, leading to even greater
reductions in crude oil prices and total revenues.
GEOGRAPHICAL CONSTRAINTS
Further market penetration by PEMEX is constrained by logistical advantages
of Canadian crude oil in the Midwest region, the various producer/refiner joint
venture relationships in the U.S. East and Gulf Coast regions and the somewhat
limited sour crude oil processing capacity in the United States.
MAJOR FACTORS LIMITING MARKET PENETRATION BY PEMEX
REFINERY COMPLEXITY REQUIREMENT
The heavy sour crude oil that dominates PEMEX's production requires
refineries with relatively high Nelson complexity factors to most efficiently
produce higher value refined petroleum products. The Nelson complexity factor
is determined by multiplying all reported unit capacities by their complexity
factor and dividing by crude oil distillation capacity. A basic topping
refinery, which essentially separates crude oil into its boiling point
fractions, has a complexity factor of 1.0. A refinery with asphalt capacity,
which typically includes a vacuum distillation unit, has a complexity factor of
1.1 to 3.0. A hydroskimming refinery, which is usually a topping refinery with
a catalytic reformer to upgrade the naphtha, has a typical complexity of 4 to
6. A cracking refinery which includes either a Fluid Catalytic Cracker (FCCU)
or a Hydrocracker to upgrade gas oil into gasoline and distillates typically
has a complexity factor range of 5 to 10. A coking refinery has a complexity
factor of 7 to 12 and includes a delayed coker, which allows full conversion of
the crude oil barrel. Mexico's crude oil is typically processed in coking
refineries to realize the full value of the crude oil barrel. Refiners without
coking capacity cannot typically process PEMEX's heavy sour crude oil
economically, except in specialty asphalt operations.
HIGH LEVEL OF SOUR CRUDE OIL CAPACITY UTILIZATION OF EXISTING REFINERIES
Due to the high utilization rate of existing heavy oil capacity, PEMEX would
find it difficult to divert its heavy crude to other users. Approximately 93%
of the 6.9 million barrels per day of sour crude oil capacity in
C-41
<PAGE>
PADDs I, II, and III was utilized in 1997 (Tables VI-3 and VI-4). Of the
underutilized refineries in PADD III in 1997 capable of processing sour crude
oil, several of these refineries have long to medium term crude oil supply
contracts, including Phillips at Sweeny, Exxon at Baytown, and Clark at Port
Arthur. Of the roughly 6.9 million barrels per day of sour crude oil refining
capacity in PADDs I, II, and III, PEMEX supplies refineries having a capacity
of 4.8 million barrels per day, or 77% of the total capacity. Most is under
contract. Typically the contract term is for one year but they are "evergreen"
which means they roll-over unless either party terminates the arrangement.
STRATEGIC AFFILIATIONS OF COMPETING PRODUCERS
Other competing producers are tying up refining capacity that might otherwise
be available to process Mexican crude oil. The impact of known producer/refiner
affiliations can be seen in the concentration of supply. For example, the total
of Middle East crude oil processed by former Saudi Aramco partners Mobil,
Chevron, Exxon and affiliate Texaco/Star Enterprise is 973 MBPD, or 68% of
Middle Eastern imports of crude oil into the United States. These will further
limit PEMEX expansion potential.
VENEZUELAN EXTRA HEAVY OIL PROJECTS
PDVSA is currently involved in four and negotiating two additional extra
heavy oil production and upgrading projects in Venezuela's Orinoco Oil Belt,
which will further limit the market for PEMEX's traditional production and
imports into the United States to the extent they include PDVSA partner
refineries which would otherwise be outlets for traditional PEMEX heavy sour
crude oil production. The affected refineries include the Mobil Chalmette
refinery, the Conoco Lake Charles refinery, and potentially, the Coastal Corpus
Christi and the Exxon refineries.
ALTERNATIVE CRUDE SUPPLY
If for some reason, PEMEX decided to divert the Maya crude away from the
Clark Port Arthur refinery, there are alternative supplies of heavy sour crude
that Clark and PACC could likely obtain.
Venezuela will be rapidly expanding its heavy crude production as world crude
demand grows as Asia recovers. OPEC quota levels will be raised so Venezuela
will not have to constrain output. In addition, the heavy oil production
(Orinoco) discussed earlier will get back on track and will add to the heavy
crude supply.
Mexico is expanding its heavy crude production from 1.6 million B/D to 2.3
million B/D by 2015. New customers will need to be found. In addition, an
examination of the refineries that purchase Mexican Maya crude indicates that a
significant portion is being run in refineries which do not have adequate
bottoms upgrading to completely upgrade the bottoms so it is run in a cracking
mode rather than in a coking mode. This means that PEMEX could realize a higher
value for the Maya if it were sold to a coking operation, like the Upgrade
Project.
Saudi Arabia is having difficulty in marketing the expanded production from
the Neutral Zone. They are pressuring Japan to take more but the Japanese are
resisting. Contracts for this crude would not be difficult to obtain.
C-42
<PAGE>
TABLE VI-1
SOUR CRUDE OIL IMPORTS
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
TOTAL SOUR CRUDE HEAVY SOUR CRUDE
--------------------------------- ---------------------------------
PADD I PADD II PADD III Total % PADD I PADD II PADD III Total %
------ ------- -------- ----- --- ------ ------- -------- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998 PEMEX.............. 27 61 1,190 1,278 23% 22 26 732 780 29%
Canada................. 59 711 5 755 14% 27 591 4 623 23%
Venezuela.............. 205 125 1,007 1,337 24% 164 38 696 898 33%
Middle East............ 163 237 1,480 1,880 34% 38 6 286 330 12%
Other.................. 71 18 118 206 4% 55 3 41 100 4%
Total.................. 524 1,152 3,799 5,476 100% 307 664 1,760 2,731 100%
1997 PEMEX.............. 23 106 1,215 1,344 25% 21 53 772 846 32%
Canada................. 38 671 0 709 13% 24 588 0 612 23%
Venezuela.............. 177 158 997 1,333 25% 156 18 696 870 33%
Middle East............ 153 170 1,240 1,563 30% 50 4 135 189 7%
Other.................. 86 36 213 335 6% 41 0 48 89 3%
Total.................. 477 1,141 3,666 5,284 100% 292 663 1,651 2,606 100%
1996 PEMEX.............. 16 115 1,078 1,210 26% 16 31 668 715 31%
Canada................. 38 509 4 551 12% 24 450 2 475 21%
Venezuela.............. 192 153 938 1,283 28% 168 93 692 953 42%
Middle East............ 171 117 1,109 1,396 30% 39 0 35 74 3%
Other.................. 63 35 125 223 5% 35 0 28 63 3%
Total.................. 480 929 3,253 4,663 100% 282 574 1,425 2,280 100%
1995 PEMEX.............. 30 28 860 918 22% 21 11 539 571 30%
Canada................. 41 524 1 566 14% 27 398 0 425 22%
Venezuela.............. 157 157 656 969 24% 141 24 457 622 32%
Middle East............ 238 101 1,083 1,422 35% 72 0 160 232 12%
Other.................. 29 3 196 228 6% 27 1 38 66 3%
Total.................. 495 812 2,795 4,102 100% 288 434 1,194 1,916 100%
1994 PEMEX.............. 55 55 730 840 21% 26 54 517 597 33%
Canada................. 61 510 1 571 14% 0 278 1 279 15%
Venezuela.............. 142 138 538 818 20% 123 6 398 527 29%
Middle East............ 239 132 1,276 1,647 41% 89 1 256 347 19%
Other.................. 26 35 119 180 4% 10 8 33 52 3%
Total.................. 523 870 2,664 4,056 100% 248 347 1,205 1,801 100%
</TABLE>
C-43
<PAGE>
TABLE VI-2
SOUR CRUDE IMPORTS BY SOURCE
(Barrels per Day)
<TABLE>
<CAPTION>
PADD I PADD II PADD III Total PADD I-III
----------------------- ------------------------- ----------------------------- -----------------------------
Light Heavy Total Light Heavy Total Light Heavy Total Light Heavy
Sour Sour PADD I Sour Sour PADD II Sour Sour PADD III Sour Sour TOTAL
------- ------- ------- ------- ------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996
Mexico........... 0 16,071 16,071 83,679 31,496 115,175 410,659 667,765 1,078,424 494,338 715,332 1,209,671
Venezuela........ 23,690 168,493 192,183 60,356 92,573 152,929 245,310 692,343 937,653 329,356 953,409 1,282,765
Canada........... 14,019 23,870 37,889 59,675 449,520 509,195 2,115 1,784 3,899 75,809 475,174 550,983
Mid East......... 132,041 38,700 170,741 116,633 0 116,633 1,073,616 34,921 1,108,537 1,322,290 73,621 1,395,911
Other............ 28,178 34,693 62,871 35,449 0 97,022 97,022 27,910 124,932 160,649 62,603 223,252
TOTAL........... 197,928 281,827 479,755 355,792 573,588 990,954 1,828,723 1,424,723 3,253,445 2,382,443 2,280,138 4,662,581
1997
Mexico........... 1,920 21,159 23,079 53,400 52,737 106,137 443,050 772,200 1,215,250 498,370 846,096 1,344,466
Venezuela........ 21,310 155,770 177,080 140,670 17,690 158,360 301,020 696,270 997,290 463,000 869,730 1,332,730
Canada........... 14,272 24,116 38,388 82,470 588,171 670,641 0 0 0 96,742 612,287 709,029
Mid East......... 102,592 49,959 152,551 165,430 4,482 169,912 1,105,488 134,940 1,240,428 1,373,510 189,381 1,562,891
Other............ 44,460 41,170 85,630 36,440 0 36,440 165,580 47,710 213,290 246,480 88,880 335,360
TOTAL........... 184,554 292,174 476,728 478,410 663,080 1,141,490 2,015,138 1,651,120 3,666,258 2,678,102 2,606,374 5,284,476
1998
Mexico........... 4,556 22,038 26,594 35,482 25,589 61,071 457,942 732,074 1,190,016 497,980 779,701 1,277,681
Venezuela........ 41,036 164,104 205,140 86,847 38,252 125,099 310,726 696,022 1,006,748 438,609 898,378 1,336,987
Canada........... 31,715 27,464 59,179 119,941 591,071 711,012 1,058 4,189 5,247 152,714 622,724 775,438
Mid East......... 124,307 38,422 162,729 231,523 5,805 237,328 1,193,682 286,151 1,479,833 1,549,512 330,378 1,879,890
Other............ 15,556 54,967 70,523 14,370 3,225 17,595 76,164 41,370 117,534 106,090 99,562 205,652
TOTAL........... 217,170 306,995 524,165 488,163 663,942 1,152,105 2,039,572 1,759,806 3,799,378 2,744,905 2,730,743 5,475,648
</TABLE>
- ------
Note: Heavy indicates less than 30(degrees) API; Sour is greater than 0.7%
sulfur
C-44
<PAGE>
TABLE VI-3
1997 SOUR CRUDE CAPACITY UTILIZATION
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Design Light Sour
----------------------- ------------------------------
Crude Light Light Heavy
Company Location Capacity Sweet Sour Sour Total Domestic Canada Offshore Total
---------------- -------------- -------- ----- ----- ----- ----- -------- ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BP Amoco Yorktown 57 -- 25 32 57 -- -- 4 4
Chevron Perth Amboy 80 -- -- 80 80 -- -- -- --
Citgo Savannah 28 -- -- 28 28 -- -- -- --
Citgo Thorofare 80 -- -- 80 80 -- -- -- --
Coastal Westville 140 140 -- -- 140 -- -- 1 1
Motiva (Star) Delaware City 140 -- 30 110 140 -- -- 25 25
Sun Philadelphia--
Girard Pt 307 207 50 50 307 -- -- -- --
Tosco Linden 240 240 -- -- 240 -- -- 2 2
United Refining Warren
Co. 67 20 22 25 67 -- 14 -- 14
Valero (Mobil) Paulsboro 149 -- 139 10 149 -- -- 138 138
Witco Chemical Bradford 10 10 -- -- 10 -- -- -- --
Young Refining Douglasville 6 -- -- 6 6 -- -- -- --
TOTAL PADD I 1,303 617 266 421 1,303 0 14.272 170 185
<CAPTION>
Design Light Sour Crude
----------------------- ------------------------------
Crude Light Light Heavy
Company Location Capacity Sweet Sour Sour Total Domestic Canada Offshore Total
---------------- -------------- -------- ----- ----- ----- ----- -------- ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BP Amoco Whiting 410 140 140 130 410 101 1 16 118
BP Amoco Toledo 147 147 -- -- 147 -- -- -- --
Citgo Lemont 145 -- 70 75 145 -- -- 86 86
Clark Oil Blue Island 75 50 25 -- 75 -- -- 7 7
Clark Oil Hartford 65 -- 40 25 65 16 10 27 53
Conoco Ponca City 160 105 55 -- 160 55 -- -- 55
Equilon (Shell) Wood River 271 100 136 35 271 181 4 32 216
Equilon (Texaco) El Dorado 100 20 60 20 100 60 1 8 69
Exxon/Mobil Joliet 204 -- 70 134 204 16 40 -- 56
Farmland Coffeyville 110 85 25 -- 110 5 -- 19 24
Koch Rosemount 286 -- -- 286 286 -- 19 -- 19
Laketon Laketon 4 -- -- 4 4 -- -- -- --
Marathon Ashland Detroit 70 40 10 20 70 6 1 -- 7
Marathon Ashland Robinson 185 185 -- -- 185 -- 1 50 51
Marathon Ashland Catlettsburg 219 -- 214 5 219 72 4 126 202
Marathon Ashland Canton 70 45 20 5 70 -- 0 17 17
Marathon Ashland St. Paul Park 70 60 -- 10 70 -- 1 2 3
Murphy Superior 36 29 -- 7 36 -- 2 -- 2
NCRA McPherson 74 49 25 -- 74 18 -- 5 23
Sinclair Tulsa 50 40 10 -- 50 10 -- -- 10
Ultramar Diamond Ardmore
Shamrock 68 23 45 -- 68 40 -- 40
Ultramar Diamond Alma
Shamrock 51 41 10 -- 51 10 -- -- 10
TOTAL PADD II 2,870 1,159 956 756 2,870 589 82 396 1,067
<CAPTION>
Total Sour
Heavy Sour Total Sour Crude Utilization
------------------------------ ------------------------------ -----------------
Lt Hvy
Company Domestic Canada Offshore Total Domestic Canada Offshore Total Sour Sour Total
- ------------------ -------- ------ -------- ----- -------- ------ -------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BP Amoco -- -- 29 29 -- -- 34 34 17% 93% 59%
Chevron -- -- 34 34 -- -- 34 34 -- 43% 43%
Citgo -- -- 15 15 -- -- 15 15 -- 54% 54%
Citgo -- -- 50 50 -- -- 50 50 -- 62% 62%
Coastal -- -- 1 1 -- -- 2 2 -- -- --
Motiva (Star) -- -- 134 134 -- -- 159 159 83% 122% 114%
Sun
-- -- -- -- -- -- -- -- -- -- --
Tosco -- -- 0 0 -- -- 2 2 -- -- --
United Refining
Co. -- 24 -- 24 -- 38 -- 38 66% 96% 82%
Valero (Mobil) -- -- 4 4 -- -- 142 142 99% 45% 96%
Witco Chemical -- -- -- -- -- -- -- -- -- -- --
Young Refining -- -- -- -- -- -- -- -- -- -- --
TOTAL PADD I 0 24.116 268 292 0 38 438 477 69% 69% 69%
<CAPTION>
Total Sour
Crude
Heavy Sour Crude Total Sour Crude Utilization
------------------------------ ------------------------------ -----------------
Lt Hvy
Company Domestic Canada Offshore Total Domestic Canada Offshore Total Sour Sour Total
- ------------------ -------- ------ -------- ----- -------- ------ -------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BP Amoco 12 124 1 138 113 125 18 256 85% 106% 95%
BP Amoco -- 12 -- 12 -- 12 -- 12 -- -- --
Citgo -- 56 -- 56 -- 56 86 142 122% 75% 98%
Clark Oil -- 0 -- 0 -- 0 7 8 29% -- 30%
Clark Oil -- 7 -- 7 16 17 27 60 131% 30% 92%
Conoco -- -- -- -- 55 -- -- 55 100% -- 100%
Equilon (Shell) -- 36 3 40 181 40 35 256 159% 113% 149%
Equilon (Texaco) -- -- 15 15 60 1 23 84 115% 76% 105%
Exxon/Mobil -- 116 -- 116 16 156 -- 172 80% 87% 84%
Farmland -- -- 1 1 5 -- 20 25 96% -- 102%
Koch -- 202 40 242 -- 221 40 261 -- 85% 91%
Laketon -- -- -- -- -- -- -- -- -- -- --
Marathon Ashland -- 16 8 24 6 16 8 31 69% 118% 102%
Marathon Ashland -- 9 -- 9 -- 10 50 61 -- -- --
Marathon Ashland -- 1 1 2 72 4 127 203 94% 32% 93%
Marathon Ashland -- -- 1 1 -- 0 18 18 86% 16% 72%
Marathon Ashland -- -- -- -- -- 1 2 3 -- -- 28%
Murphy -- 8 -- 8 -- 10 -- 10 -- 120% 146%
NCRA -- -- -- -- 18 -- 5 23 90% -- 90%
Sinclair -- -- 4 4 10 -- 4 14 100% -- 141%
Ultramar Diamond
Shamrock -- -- -- -- 40 -- -- 40 89% -- 89%
Ultramar Diamond
Shamrock -- -- -- -- 10 -- -- 10 100% -- 100%
TOTAL PADD II 12 588 75 675 601 671 471 1,743 112% 89% 102%
</TABLE>
C-45
<PAGE>
TABLE VI-3--(Continued)
1997 SOUR CRUDE CAPACITY UTILIZATION
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Design Light Sour Crude
------------------------ ------------------------------
Crude Light Light Heavy
Company Location Capacity Sweet Sour Sour Total Domestic Canada Offshore Total
- ------- -------- -------- ----- ----- ----- ------ -------- ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Berry Petroleum Stevens 7 -- -- 7 7 -- -- -- --
BP Amoco Texas City 437 200 87 150 437 47 -- 59 107
Chevron Pascagoula 295 -- 145 150 295 5 -- 135 141
Chevron El Paso 90 -- 90 -- 90 86 -- -- 86
Citgo Lake Charles 304 90 14 200 304 -- -- 15 15
Citgo Corpus Christi 133 -- 33 100 133 -- -- 36 36
Clark Oil Port Arthur 212 50 137 25 212 1 -- 138 139
Coastal Mobile 19 -- -- 19 19 -- -- -- --
Coastal Corpus Christi 100 5 35 60 100 -- -- 25 25
Conoco Lake Charles 226 60 -- 166 226 -- -- 59 59
Cross Oil Smackover 6 -- -- 6 6 -- -- -- --
Crown Tyler 60 48 12 -- 60 -- -- -- --
Crown Houston 100 80 20 -- 100 10 -- 14 24
Ergon Refining Vicksburg 25 -- -- 25 25 -- -- -- --
Exxon Mobil Baton Rouge 450 200 180 70 450 28 -- 146 174
Exxon Mobil Chalmette 170 90 -- 80 170 -- -- 3 3
Exxon Mobil Baytown 427 50 227 150 427 14 -- 228 242
Exxon Mobil Beaumont 320 30 200 90 320 19 -- 134 153
Hunt Tuscaloosa 43 -- -- 43 43 -- -- -- --
Koch Corpus Christi 280 90 190 -- 280 -- -- 57 57
Lion El Dorado 53 -- 45 8 53 9 -- 38 47
Lyondell Houston 239 -- -- 239 239 -- -- 2 2
Marathon Ashland Garyville 225 -- 170 55 225 49 -- 153 201
Motiva (Shell) Norco 219 219 -- -- 219 -- -- 12 12
Motiva (Star) Convent 230 -- 220 10 230 -- -- 223 223
Motiva (Star) Port Arthur 235 -- 135 100 235 -- -- 149 149
Murphy Meraux 95 -- 95 -- 95 -- -- 99 99
Navajo Artesia/Lovington 60 -- 60 -- 60 59 -- -- 59
Neste Trifinery Corpus Christi 30 -- -- 30 30 -- -- -- --
Phillips Sweeny 200 75 125 -- 200 -- -- 78 78
Phillips Borger 120 10 110 -- 120 114 -- -- 114
Shell Deer Park 256 15 30 211 256 -- -- 24 24
Southland Oil Lumberton 6 -- -- 6 6 -- -- -- --
Southland Oil Sandersville 11 -- -- 11 11 -- -- -- --
Total (Fina) Port Arthur 179 50 129 -- 179 41 -- 65 107
Total (Fina) Big Spring 58 -- 58 -- 58 54 -- -- 54
Ultramar Diamond
Shamrock Three Rivers 80 80 -- -- 80 -- -- 2 2
Ultramar Diamond
Shamrock Sunray/McKee 135 95 40 -- 135 41 -- -- 41
Valero Corpus Christi 30 30 -- -- 30 -- -- 10 10
Valero (Basis) Houston 68 30 38 -- 68 5 -- 13 18
Valero (Basis) Texas City 125 16 105 5 125 31 -- 98 129
TOTAL PADD III 6,356 1,612 2,729 2,016 6,356 615 -- 2,015 2,630
TOTAL PADDS I-
III 10,530 3,388 3,950 3,192 10,530 1,204 97 2,581 3,862
<CAPTION>
Crude
Heavy Sour Crude Total Sour Crude Utilization
------------------------------ ------------------------------ -----------------
Lt Hvy
Company Domestic Canada Offshore Total Domestic Canada Offshore Total Sour Sour Total
- ------- -------- ------ -------- ----- -------- ------ -------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Berry Petroleum 6 -- -- 6 6 -- -- 6 -- 84% 84%
BP Amoco -- -- 96 96 47 -- 155 203 123% 64% 86%
Chevron -- -- 161 161 6 -- 296 302 97% 107% 102%
Chevron -- -- -- -- 86 -- -- 86 95% -- 95%
Citgo -- -- 180 180 -- -- 196 196 110% 90% 91%
Citgo -- -- 86 86 -- -- 122 122 111% 86% 92%
Clark Oil -- -- 28 28 1 -- 166 168 102% 112% 103%
Coastal -- -- 13 13 -- -- 13 13 -- 68% 68%
Coastal -- -- 62 62 -- -- 87 87 72% 104% 92%
Conoco -- -- 105 105 -- -- 164 164 -- 63% 99%
Cross Oil 6 -- -- 6 6 -- -- 6 -- 97% 97%
Crown -- -- -- -- -- -- -- -- -- -- --
Crown -- -- -- -- 10 -- 14 24 119% -- 119%
Ergon Refining -- -- 22 22 -- -- 22 22 -- 90% 90%
Exxon Mobil 42 -- 31 73 70 -- 177 247 97% 104% 99%
Exxon Mobil -- -- 65 65 -- -- 68 68 -- 82% 85%
Exxon Mobil 103 -- 86 191 117 -- 315 433 107% 127% 115%
Exxon Mobil -- -- 89 89 19 -- 223 243 77% 99% 84%
Hunt 21 -- 17 38 21 -- 17 38 -- 89% 89%
Koch -- -- 23 23 -- -- 79 79 30% -- 42%
Lion 4 -- -- 4 13 -- 38 51 106% 50% 98%
Lyondell -- -- 213 213 -- -- 215 215 -- 89% 90%
Marathon Ashland -- -- 22 22 49 -- 175 224 118% 40% 99%
Motiva (Shell) -- -- 2 2 -- -- 14 14 -- -- --
Motiva (Star) -- -- 5 5 -- -- 229 229 102% 52% 99%
Motiva (Star) -- -- 85 85 -- -- 234 234 110% 85% 99%
Murphy -- -- -- -- -- -- -- 99 99 104% -- 104%
Navajo -- -- -- -- 59 -- -- 59 98% -- 98%
Neste Trifinery -- -- 24 24 -- -- 24 24 -- 79% 79%
Phillips -- -- -- -- -- -- 78 78 62% -- 62%
Phillips -- -- -- -- 114 -- -- 114 104% -- 104%
Shell -- -- 224 224 -- -- 248 248 79% 106% 103%
Southland Oil 2 -- -- 2 2 -- -- 2 -- 33% 33%
Southland Oil 4 -- -- 4 4 -- -- 4 -- 34% 34%
Total (Fina) -- -- -- -- 41 -- 41 107 83% -- 83%
Total (Fina) -- -- -- -- 54 -- -- 54 93% -- 93%
Ultramar Diamond
Shamrock -- -- -- -- -- -- 2 2 -- -- --
Ultramar Diamond
Shamrock -- -- -- -- 41 -- -- 41 102% -- 102%
Valero -- -- 6 6 -- -- 15 15 -- -- --
Valero (Basis) -- -- -- -- 5 -- 13 18 48% -- 48%
Valero (Basis) -- -- 3 3 31 -- 101 132 122% 53% 119%
TOTAL PADD III 168 -- 1,651 1,839 803 -- 3,666 4,469 96% 91% 94%
TOTAL PADDS I-
III 200 612 1,994 2,806 1,404 709 4,575 6,688 96% 68% 84%
</TABLE>
C-46
<PAGE>
TABLE VI-4
1996 SOUR CRUDE CAPACITY UTILIZATION
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Design Light Sour Crude Heavy Sour Crude
----------------------- ------------------------------ ------------------------------
Crude Light Light Heavy
Company Location Capacity Sweet Sour Sour Total Domestic Canada Offshore Total Domestic Canada Offshore Total
- ------- -------- -------- ----- ----- ----- ----- -------- ------ -------- ----- -------- ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BP Amoco Yorktown 57 -- 25 32 57 -- -- 12 12 -- -- 30 30
Chevron Perth Amboy 80 -- -- 80 80 -- -- -- -- -- -- 32 32
Citgo Savannah 28 -- -- 28 28 -- -- -- -- -- -- 15 15
Citgo Thorofare 80 -- -- 80 80 -- -- -- -- -- -- 39 39
Motiva (Star) Delaware City 140 -- 30 110 140 -- -- 11 11 -- -- 121 121
Sun Philadelphia
--Girard Pt 307 207 50 50 307 -- -- 22 22 -- -- 17 17
Sun Marcus Hook 175 175 -- -- 175 -- -- 1 1 -- -- -- --
Tosco Linden 240 240 -- -- 240 -- -- 1 1 -- -- -- --
United Refining
Co. Warren 67 20 22 25 67 -- 14 -- 14 -- 24 -- 24
Valero (Mobil) Paulsboro 149 -- 139 10 149 -- -- 136 136 -- -- 3 3
Young Refining Douglasville 6 -- -- 6 6 -- -- -- -- -- -- -- --
TOTAL PADD I 1,328 642 266 421 1,328 -- 14 184 198 -- 24 258 282
<CAPTION>
Design Light Sour Crude Heavy Sour Crude
----------------------- ------------------------------ ------------------------------
Crude Light Light Heavy
Company Location Capacity Sweet Sour Sour Total Domestic Canada Offshore Total Domestic Canada Offshore Total
- ------- -------- -------- ----- ----- ----- ----- -------- ------ -------- ----- -------- ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BP Amoco Whiting 410 140 140 130 410 116 1 14 131 12 109 11 132
BP Amoco Toledo 147 147 -- -- 147 -- -- 0 0 -- 9 -- 9
Citgo Lemont 145 -- 70 75 145 -- 2 55 57 -- 26 61 86
Clark Oil Blue Island 75 55 20 -- 75 -- 9 11 19 -- -- -- --
Clark Oil Hartford 65 -- 40 25 65 12 1 41 54 -- -- -- --
Conoco Ponca City 155 100 55 -- 155 55 -- -- 55 -- -- -- --
Equilon (Shell) Wood River 271 100 136 35 271 163 -- 27 191 -- -- 13 13
Equilon (Texaco) El Dorado 100 20 60 20 100 80 -- 1 81 -- -- 11 11
Exxon Mobil Joliet 204 -- 70 134 204 27 28 -- 56 -- 105 -- 105
Farmland Coffeyville 110 110 -- -- 110 5 -- 5 10 -- -- -- --
Koch Rosemount 286 -- -- 286 286 -- 17 -- 17 -- 177 19 196
Lakelon Lakeon 4 -- -- 4 4 -- -- -- -- -- -- -- --
Marathon Ashland Detroit 70 40 10 20 70 10 1 1 11 -- 8 6 15
Marathon Ashland Robinson 166 166 -- -- 166 - -- 3 3 -- 7 -- 7
Marathon Ashland Callettsburg 219 -- 214 5 219 79 -- 125 203 -- -- -- --
Marathon Ashland Canton 66 41 20 5 66 -- 1 16 16 -- -- -- --
Marathon Ashland St. Paul Park 69 59 -- 10 69 -- -- -- -- -- -- -- --
Murphy Superior 36 29 -- 7 36 -- 0 -- 0 -- 7 -- 7
NCRA McPherson 74 49 25 -- 74 23 -- -- 23 -- -- -- --
Sinclair Tulsa 50 40 10 -- 50 10 -- -- 10 -- -- 3 3
Ultramar Diamond
Shamrock Ardmore 68 23 45 -- 68 40 -- -- 40 -- -- -- --
Ultramar Diamond
Shamrock Alma 46 36 10 -- 46 10 -- -- 10 -- -- -- --
TOTAL PADD II 2,836 1,154 926 756 2,836 630 59,675 296 986 12 449.5 124 585
<CAPTION>
Total Sour
Crude
Total Sour Crude Utilization
------------------------------ -----------------
Lt Hvy
Company Domestic Canada Offshore Total Sour Sour Total
- ------- -------- ------ -------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
BP Amoco -- -- 43 43 49% 96% 75%
Chevron -- -- 32 32 -- 40% 40%
Citgo -- -- 15 15 -- 54% 54%
Citgo -- -- 39 39 -- 49% 49%
Motiva (Star) -- -- 132 132 35% 110% 94%
Sun
-- -- 40 40 45% 34% 40%
Sun -- -- 1 1 -- -- --
Tosco -- -- 1 1 -- -- --
United Refining
Co. -- 38 -- 36 65% 95% 81%
Valero (Mobil) -- -- 139 139 98% 30% 93%
Young Refining -- -- -- -- -- -- --
TOTAL PADD I -- 38 442 480 74% 67% 70%
<CAPTION>
Total Sour
Crude
Total Sour Crude Utilization
------------------------------ -----------------
Lt Hvy
Company Domestic Canada Offshore Total Sour Sour Total
- ------- -------- ------ -------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
BP Amoco 128 110 25 263 93% 102% 97%
BP Amoco -- 9 0 10 -- -- --
Citgo -- 28 116 143 81% 115% 99%
Clark Oil -- 9 11 19 96% -- 96%
Clark Oil 12 1 41 54 135% -- 83%
Conoco 55 -- -- 55 100% -- 100%
Equilon (Shell) 163 -- 40 203 140% 36% 119%
Equilon (Texaco) 80 -- 12 92 135% 57% 115%
Exxon Mobil 27 134 -- 161 80% 79% 79%
Farmland 5 -- 5 10 -- -- --
Koch -- 194 19 212 -- 68% 74%
Lakelon -- -- -- -- -- -- --
Marathon Ashland 10 9 7 26 111% 75% 87%
Marathon Ashland -- 7 3 10 -- -- --
Marathon Ashland 79 -- 125 203 95% -- 93%
Marathon Ashland -- 1 15 16 81% -- 65%
Marathon Ashland -- -- -- -- -- -- --
Murphy -- 7 -- 7 -- 96% 97%
NCRA 23 -- -- 23 93% -- 93%
Sinclair 10 -- 3 13 100% -- 129%
Ultramar Diamond
Shamrock 40 -- -- 40 89% -- 89%
Ultramar Diamond
Shamrock 10 -- -- 10 100% -- 100%
TOTAL PADD II 642 509 420 1,571 107% 77% 55%
</TABLE>
C-47
<PAGE>
TABLE VI-4--(Continued)
1996 SOUR CRUDE CAPACITY UTILIZATION
(Thousand Barrels per Day)
<TABLE>
<CAPTION>
Design Light Sour Crude
------------------------ ------------------------------
Crude Light Light Heavy
Company Location Capacity Sweet Sour Sour Total Domestic Canada Offshore Total
- ------- -------- -------- ----- ----- ----- ------ -------- ------ -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Berry Petroleum Stevens 7 -- -- 7 7 -- -- -- --
BP Amoco Texas City 433 200 83 150 433 47 -- 54 101
Chevron Pascagoula 295 -- 145 150 295 0 -- 168 168
Chevron El Paso 90 -- 90 -- 90 82 -- -- 82
Citgo Lake Charles 304 90 14 200 304 -- -- 15 15
Citgo Corpus Christi 133 -- 33 100 133 -- -- 33 33
Clark Oil Port Arthur 212 50 137 25 212 47 -- 56 102
Coastal Mobile 15 -- -- 15 15 -- -- -- --
Coastal Corpus Christi 100 5 40 55 100 14 -- 11 25
Conoco Lake Charles 226 60 -- 166 226 -- -- 8 8
Cross Oil Smackover 6 -- -- 6 6 -- -- -- --
Crown Houston 100 90 10 -- 100 10 -- 4 14
Ergon Refining Vicksburg 25 -- -- 25 25 -- -- -- --
Exxon Mobil Baton Rouge 432 200 162 70 432 28 -- 83 112
Exxon Mobil 176 96 -- 80 176 -- -- 3 3
Exxon Mobil Baytown 411 50 211 150 411 20 -- 216 236
Exxon Mobil Beaumont 320 30 200 90 320 15 -- 166 181
Hunt Tuscaloosa 43 -- -- 43 43 -- -- 1 1
Koch Corpus Christi 280 90 190 -- 280 -- -- 35 35
Lion El Dorado 53 -- 45 8 53 12 -- 31 43
Lyondell Houston 258 -- -- 258 258 -- -- 27 27
Marathon Ashland Garyville 225 -- 170 55 225 -- -- 187 187
Marathon Ashland Texas City 70 70 -- -- 70 -- -- -- --
Motiva (Star) Convent 230 -- 220 10 230 -- -- 207 207
Motiva (Star) Port Arthur 235 -- 135 100 235 -- -- 155 155
Murphy Meraux 95 5 90 -- 95 -- 2 77 79
Navajo Artesia/Lovington 60 -- 60 -- 60 59 -- -- 59
Neste Trifinery Corpus Christi 30 -- -- 30 30 -- -- -- --
Phillips Sweeny 200 75 125 -- 200 13 -- 114 126
Phillips Borger 120 10 110 -- 120 102 -- -- 102
Shell Deer Park 256 15 30 211 256 15 -- 30 45
Shell
Chemical Co. Saraland 76 76 -- -- 76 -- -- 4 4
Southland Oil Lumberton 6 -- -- 6 6 -- -- -- --
Southland Oil Sandersville 11 -- -- 11 11 -- -- -- --
Total (Fina) Port Arthur 179 50 129 -- 179 58 -- 55 113
Total (Fina) Big Spring 58 -- 58 -- 58 45 -- -- 45
Ultramar Diamond
Shamrock Three Rivers 80 80 -- -- 80 -- -- -- --
Ultramar Diamond
Shamrock Sunray 135 95 40 -- 135 41 -- -- 41
Valero (Basis) Houston 68 30 38 -- 68 36 -- 21 57
Valero (Basis) Texas City 125 40 80 5 125 19 -- 68 84
TOTAL III 6,176 1,507 2,644 2,025 8,176 662 2,110 1,826 2,489
TOTAL Padds
I-III 10,340 3,304 3,835 3,202 10,340 1,292 76 2,305 3,674
<CAPTION>
Total Sour
Crude
Heavy Sour Crude Total Sour Crude Utilization
------------------------------ ------------------------------ -----------------
Lt Hvy
Company Domestic Canada Offshore Total Domestic Canada Offshore Total Sour Sour Total
- ------- -------- ------ -------- ----- -------- ------ -------- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Berry Petroleum 6 -- -- 6 6 -- -- 6 -- 89% 89%
BP Amoco -- 1 85 86 47 1 139 187 122% 57% 80%
Chevron -- -- 134 134 0 -- 302 302 116% 90% 103%
Chevron -- -- -- -- 82 -- -- 82 91% -- 91%
Citgo -- -- 171 171 -- -- 166 186 105% 86% 87%
Citgo -- -- 103 103 -- -- 135 136 102% 103% 103%
Clark Oil 2 -- 1 4 49 -- 57 106 75% 15% 65%
Coastal -- -- 14 14 -- -- 14 14 -- 93% 93%
Coastal -- -- 55 55 14 -- 66 80 63% 99% 84%
Conoco -- -- 119 119 -- -- 127 127 -- 72% 77%
Cross Oil 6 -- -- 6 6 -- -- 6 -- 99% 99%
Crown -- -- -- -- 10 -- 4 14 138% -- 138%
Ergon Refining 1 -- 18 19 1 -- 18 19 -- 75% 75%
Exxon Mobil 42 -- 34 76 70 -- 117 187 68% 109% 81%
Exxon Mobil -- -- 78 78 -- -- 81 81 -- 98% 101%
Exxon Mobil 103 -- 28 131 123 -- 245 367 112% 87% 102%
Exxon Mobil -- 1 77 78 15 1 243 258 90% 86% 89%
Hunt 20 -- 18 37 20 -- 19 38 -- 86% 89%
Koch -- -- -- -- -- -- 35 35 19% -- 19%
Lion 4 -- -- 4 16 -- 31 47 97% 50% 89%
Lyondell -- -- 144 144 -- -- 171 171 -- 56% 66%
Marathon Ashland -- -- 29 29 -- -- 216 215 110% 53% 96%
Marathon Ashland -- -- 2 2 -- -- 2 2 -- -- --
Motiva (Star) -- -- 3 3 -- -- 210 210 94% 29% 91%
Motiva (Star) -- -- 80 80 -- -- 234 234 114% 80% 100%
Murphy -- -- -- -- -- 2 77 79 68% -- 88%
Navajo -- -- -- -- 59 -- -- 59 98% -- 98%
Neste Trifinery -- -- 22 22 -- -- 22 22 -- 74% 74%
Phillips -- -- -- -- 13 -- 114 126 101% -- 101%
Phillips -- -- -- -- 102 -- -- 102 93% -- 93%
Shell -- -- 190 190 15 -- 220 235 150% 90% 97%
Shell
Chemical Co. -- -- -- -- -- -- 4 4 -- -- --
Southland Oil 2 -- -- 2 2 -- -- 2 -- 40% 40%
Southland Oil 4 -- -- 4 4 -- -- 4 -- 36% 36%
Total (Fina) -- -- -- -- 58 -- 56 113 88% -- 88%
Total (Fina) -- -- -- -- 45 -- -- 45 77% -- 77%
Ultramar Diamond
Shamrock -- -- 1 1 -- -- 1 1 -- -- --
Ultramar Diamond
Shamrock -- -- -- -- 41 -- -- 41 102% -- 102%
Valero (Basis) -- -- 3 3 36 -- 24 60 153% -- 160%
Valero (Basis) -- -- 15 15 19 -- 81 100 105% 306% 117%
TOTAL III 190 1,775 1,423 1,615 852 4 3,249 4,104 94% 80% 66%
TOTAL Padds
I-III 202 475 1,805 2,482 1,494 551 4,111 6,155 96% 78% 60%
</TABLE>
C-48
<PAGE>
TABLE VI-5
MEXICAN HEAVY SOUR CRUDE IMPORTERS
<TABLE>
<CAPTION>
Thousand Barrels per Day
------------------------
1998% 1998 1997 1996 1995 1994
----- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Deer Park Refg. ................................. 20.1 157 169 164 105 10
Exxon Mobil...................................... 16.6 130 122 109 97 66
Conoco........................................... 12.1 94 88 77 63 82
Chevron.......................................... 11.5 90 120 123 116 130
BP Amoco......................................... 9.8 77 72 66 47 67
CITGO............................................ 6.4 50 54 36 16 53
Koch Industries.................................. 5.4 42 44 17 23 36
Chalmette Refining............................... 3.5 27 46 37 23 25
Clark............................................ 3.4 27 24 1 14 29
Coastal.......................................... 3.1 24 26 14 17 14
Equilon.......................................... 1.8 14 3 10 -- 10
Marathon Ashland................................. 1.3 10 18 16 21 29
Hunt............................................. 1.2 10 8 9 8 6
Other............................................ 3.7 29 52 36 23 41
----- --- --- --- --- ---
Total............................................ 100.0 780 846 715 571 597
</TABLE>
C-49
<PAGE>
VII. CRUDE OIL PRICING AND LIGHT/HEAVY DIFFERENTIAL
CRUDE OIL PRICING
The overall level of crude oil prices is set by the cost of production and
the balance between the demand for refined products and the supply of crude
oil. If the overall level of prices is high, the supply of crude will tend to
increase because of the economic attractiveness of developing new reserves or
producing existing reserves at higher rates. At the same time, high prices tend
to cause product demand to decrease as relatively less expensive alternative
fuels such as coal, natural gas and nuclear energy are substituted for crude
oil. The resulting imbalance of supply and demand tends to drive prices down.
Similarly, if the price is low, demand is generally stimulated, alternative
energy supply development is constrained, and adding new reserves becomes less
economical. Ultimately, the low prices cause demand to approach production
capacity limits and the resulting competition for supply drives prices back up.
The world supply of crude oils is assumed to be consumed in the most economic
manner subject to political and structural constraints. The pattern of world
crude oil movement establishes the price equalization point for each crude oil
and the crude oils it will compete against in that market. The differential
values of crude oils are determined by the prices of products in the market,
yields of the crude oils in the refineries in which they are used, and
processing costs.
Purvin & Gertz uses the price of Brent crude oil (light, sweet), FOB Sullom
Voe as the basis for forecasting the prices of major crude oils. Brent serves
both North American and European markets and competes directly with the Middle
Eastern and African crude oils that serve all major markets. The market prices
of other crude oils are based on the price of Brent and are developed through
an analysis of trading patterns and quality adjustments. Both historical and
forecast prices for the various crude oils considered in current and constant
dollars, are shown in Tables VII-1 and VII-2, respectively.
In an interactive process, product prices for each forecast year are
calculated based on expected returns on conversion capacity (which are tied to
excesses and shortages of capacity), which is an element of the base crude
forecast. Crude prices are then determined as a function of the expected
relative yield of a stream of crude oil processed using the type of refinery
configuration that has been determined to be the price-setting mechanism in a
given market, such as vacuum gas oil cracking in the U.S. Gulf Coast. Using the
product price forecast and the relative yields to Brent (or another marker
crude), the relative prices of the various crudes can be calculated. The price
level of light products relative to heavy products will directionally impact
the relative value of light and heavy crudes and the light/heavy differential.
Heavy crudes, when run in a cracking mode, will produce more residual fuel oil
than light crudes. If the differential for light products versus heavy products
is wide, the heavy crude value will be lowered relative to a light crude and
the differential will be wide. The reverse is also true, producing narrow
differentials.
LIGHT/HEAVY DIFFERENTIAL
For the purposes of this study and the Upgrade Project, the light/heavy
differential has been defined as the difference between the respective spot
prices of WTI at Cushing for the light crude and Maya FOB Mexico for the heavy
crude.
FACTORS THAT AFFECT THE LIGHT/HEAVY DIFFERENTIAL
The light/heavy differential is the result of a complex balance of a number
of factors, such as:
1. Demand for light products: The overall demand for light products, such
as gasoline and distillates, determines the total amount of crude oil to
be processed, as well as the amount of heavy feedstock available to be
converted into light products or burned as fuel.
C-50
<PAGE>
2. Demand for heavy products relative to demand for light products: As the
relative proportion of light products in the overall demand mix
increases, more of the heavy portion of each crude barrel must undergo
conversion into lighter products in order to satisfy light product
demand. The reverse situation can occur as well.
3. Supply of heavy crude: As the quality of the crude oil produced becomes
heavier, relatively more conversion capacity is required to process it
and meet the requirements of the market, assuming light product demand
remains stable.
4. Conversion Capacity heavy feedstock to be upgraded and the corresponding
need for conversion capacity. The amount of conversion capacity existing
and being built determines the extent to which refiners can upgrade
available heavy feedstock into light products. The balance between the
demand for upgraded heavy feedstock and available conversion capacity
affects the light/heavy differential.
RECENT TRENDS IN THE CONVERSION CAPACITY SUPPLY/DEMAND BALANCE
In the late 1980s, the balance between conversion capacity and heavy
feedstock was tight, with little or no excess capacity. As a result, returns on
investment to refiners were sufficient to motivate new investments in capacity.
By the early 1990s, the rate of addition of conversion capacity considerably
exceeded the needed level. Many producers added this capacity with the
intention of processing heavy crude into low sulfur diesel and reformulated
gasoline. Many refiners found the most economic way of accomplishing this was
to combine various refinery modifications made in response to regulatory
changes with expansions of conversion capacity. Since conversion capacity is
generally the most profitable increment of refining, many refiners believed
that increasing it was the most effective way to maximize returns on product
quality improvement investments. However, because so many refiners recognized
the potential benefit of increasing conversion capacity, an overbuilding of
such capacity resulted. The overabundance of conversion capacity drove up
demand for heavy feedstock and resulted in a narrowing of the light/heavy
differential through 1995.
A recovery in the light/heavy differential occurred in 1996 and 1997. While
this recovery was due in part to temporary refinery operating problems at
several major refinery units, which decreased the availability of conversion
capacity, this recovery was primarily driven by the rising output of heavy
crudes in the Western Hemisphere. This increasing production of heavy crude
resulted in severe price competition and residual fuel oil oversupply. The
spreads reached a peak late in 1997 and early 1998 due to these factors.
C-51
<PAGE>
In April 1998, the trends began to reverse and the light/heavy differential
began to narrow. This reversal was brought about by the confluence of a number
of factors. These included the effects of the Asian crisis, which reduced
demand for refined products and opened up conversion capacity worldwide. In
addition, low oil prices and high natural gas prices in the U.S. caused demand
for residual fuel to increase rather dramatically. At the same time, export
demand for residual fuel increased sharply due to El Nino related hydropower
shortages in Mexico.
[GRAPHIC OF FIGURE V-11-1-WORLD CONVERSION CAPACITY CHANGES]
Although the rate of increase in conversion capacity fell sharply after 1994,
several major projects are currently underway. In addition, several conversion
projects are linked to supplies of heavy crude from Venezuela and Mexico that
we expect to absorb increases in heavy crude production. Figures VII-1 andVII-2
illustrate the addition of conversion capacity both worldwide and in the U.S.
Net additions in recent years have been at a rate of 2% in the U.S. and nearly
4% worldwide.
[GRAPHIC OF FIGURE V-11-2-U.S. CONVERSION CAPACITY CHANGES]
C-52
<PAGE>
RECENT TRENDS IN THE LIGHT/HEAVY DIFFERENTIAL
The recent heavy crude production cuts by Venezuela and Canada are causing
the light/heavy differential to narrow currently. At the same time, new
conversion capacity is being brought on and is absorbing any excess heavy
feedstock, thereby strengthening heavy feedstock prices and further narrowing
the differential. In addition, high natural gas prices coupled with low
residual fuel oil prices are encouraging the burning of resid, thereby
squeezing the heavy feedstock balance and narrowing the light/heavy
differential even further. Even so, the differential averaged about $5.00 over
the past six months.
Domestic supply constraints in 1998 increased the price of WTI above the
level which would otherwise be expected given the global supply-demand balance.
These constraints are in the process of being reversed, and we expect this to
reduce the price of WTI. Because these supply constraints did not have a
significant impact on the Gulf Coast price of Maya, Purvin & Gertz expects the
light/heavy differential to contract as WTI prices decline relative to Maya.
Over the short term, the absolute price of WTI is likely to remain in the $15
to $20 per barrel range. Low demand for petroleum caused by the continuation of
the Asian financial crisis will cause Venezuela and other OPEC producers to
constrain production in the short term. Short term production will be further
constrained under the terms of the recent OPEC agreement. Mexico has agreed to
constrain exports as well. These factors will tend to keep the light/heavy
differential around $5.00 in the short term (i.e. through 2000).
VOLATILITY OF THE LIGHT/HEAVY DIFFERENTIAL
The changing balances between the key factors discussed above historically
have caused a considerable amount of volatility in the light/heavy differential
(Figure VII-3).
[GRAPHIC OF FIGURE VII-3-WTI CUSHING minus MAYA FOB]
C-53
<PAGE>
Month to month variations can be expected to continue in the future since
both end-product and crude oil prices fluctuate daily due to both short-term
speculative activity and fundamental changes in the key drivers over a longer
period of time. Some of this volatility is smoothed out when six month moving
average data is used (Figure VII-4). For the time period from January 1988 to
March 1999, the six month period moving average of the light/heavy differential
ranged from a high of $8.90 to a low of $3.76 with an average of $5.83.
[GRAPHIC OF FIGURE VII-4-WTI CUSHING minus MAYA FOB MEXICO (6 MONTH MOVING
AVERAGE)]
As a result of the Gulf War, the differential increased sharply in the 1st
quarter of 1990. This increase occurred as crude prices escalated rapidly as
both production and conversion capacity in Iraq and Kuwait were lost. Other
crude producers increased output of heavy crude to compensate. Refineries also
increased runs to compensate for the perceived product shortage. The result was
that residual fuel oil production increased as more heavy crude was run in
lower conversion operations which were not capable of fully upgrading the heavy
feedstock. As the balance was restored the light/heavy differential came off
these highs.
C-54
<PAGE>
LIGHT/HEAVY DIFFERENTIAL FORECAST
We believe that after 2000, the light/heavy differential will widen (Figure
VII-5) as the key drivers are projected to result in a wider differential:
[GRAPHIC OF FIGURE VII-5-WTI CUSHING minus MAYA FOB MEXICO]
1. Demand for light products will increase rapidly (particularly in Asia)
as the world economy improves, necessitating more crude processing.
2. Crude prices will increase (Tables VII-1 and VII-2) as demand for crude
runs increases due to supply/demand balance tightening.
3. Crude production will increase (particularly heavy crude) as demand for
crude increases and higher prices encourage the development of existing
and new fields.
4. Venezuela, Mexico and Canada will expedite heavy oil production once
OPEC production restrictions are lifted. Typically, producers respond to
production limitations by curtailing production of heavy crude
disproportionately to production of light crude, primarily because
producing heavy crude is less profitable on a per-barrel basis. Assuming
producers respond to the most recent OPEC cutbacks in this manner, heavy
oil production may decrease in the short term, but will increase sharply
once the production and export restrictions are lifted. Thus, there will
be an abundant supply of heavy crude oil for the duration of the Upgrade
Project.
5. The combination of increased light product demand and increased heavy
crude production will increase demand for conversion hardware faster
than new conversion capacity can be added, due largely to delays in
building projects. Therefore, refiners will be forced to process heavy
crude oil in refineries that are incapable of fully upgrading heavy
feedstock. As a result, excess residual fuel oil will be produced until
sufficient conversion capacity is added to reduce the overhang of heavy
feedstock from the market. The market should reach equilibrium in
approximately 2005, with the light/heavy differential stabilizing at
nearly $6 per barrel in real terms from this point forward, with short
term fluctuations around this level.
USGC REFINERY MARGINS
Refinery margins were very low for most of the 1980s because of excess
capacity resulting from the prior decline in product demand in the early 1980s.
By the later 1980s, capacity had been largely rationalized, demand was once
again growing and margins strengthened considerably. The industry did not enjoy
a very long respite, as a wave of refining investment resulted in a return of
over capacity.
C-55
<PAGE>
In the following section, the marginal refinery for the USGC is developed and
margins as a function of complexity and crude type are projected. These margins
and grade differentials between products are used to forecast a consistent set
of product prices. Forecasts for the benchmark margins along with the forecast
of USGC product prices are given in Tables VII-3 through VII-8.
DRIVERS OF REFINERY PROFITABILITY
Refinery profitability is driven primarily by supply/demand pressures.
Capacity utilization, both in overall refinery capacity as well as conversion
capacity, is the most direct measure of supply/demand pressures. Of course, in
the short term, excessive capacity utilization can create excess supply and put
downward pressures on margins. However, if an industry needs to operate at near
capacity to meet demand, margins generally are good.
Rather than using domestic capacity to produce the needed demand, imports
from foreign sources can also meet these requirements. Availability of imports
depends on the worldwide balance and the amount of spare capacity in areas such
as Europe and the Caribbean, which can ship products to the U.S.
Over the longer term, capital expenditures measure the amount of new capacity
coming onstream, which can influence capacity utilization. On the other hand,
required capital expenditures in a low margin environment can force shutdowns
of facilities, further tightening the supply/demand balance. Conversely, if
margins are strong, capital expenditures can lead to overbuilding of capacity.
Commodity markets are a wild card in the drivers of refinery profitability.
At the minimum, these commodity markets greatly enhance the sensitivity of
margin to small supply/demand imbalances and create drastic short term cyclic
behavior. On a broader basis, commodity markets greatly increase the number of
participants in the market and the increased competition tends to drive down
margins, even when the supply/demand balance is only marginally long. Each of
these drivers will be discussed subsequently.
[GRAPHIC OF FIGURE VII-6-RELATIVE MARGIN INDICATOR FOR 29 USGC REFINERIES
(PPI)]
C-56
<PAGE>
[GRAPHIC OF FIGURE VII-7-USGC LLS CRACKING MARGINS AFTER VARIABLE COSTS]
[GRAPHIC OF FIGURE V-II-8 USGC LLS CRACKING VARIABLE COST MARGIN]
C-57
<PAGE>
Capacity Utilization
Capacity utilization is an important driver of margins because it is a
measure of supply/demand pressure. High utilization rates make it difficult to
respond quickly to unexpected market imbalances and cause prices to be bid up
to attract supplies. Capacity utilization is also important in determining the
marginal refinery economics serving a region; the higher the utilization rate,
the less efficient the marginal supplier.
The marginal USGC refinery has continually become more efficient. Production
of residual fuel oil by USGC refineries have now fallen to nearly 4% of crude
runs. Operating costs have steadily been reduced. Our analysis shows that
virtually all USGC refineries have some form of bottoms upgrading, ranging from
direct cat cracking of "clean" resids to hydroprocessing and coking. In the
late 1980s, the marginal refinery had no bottoms upgrading and long term
margins needed to support full cost economics of the cracking refinery. The
processing power index (PPI) is our way of measuring refinery complexity.
Unlike other measures of complexity, it is designed to measure margin
generating capability, rather than replacement cost. We have found that
refinery margins depend strongly on the processing power of the refinery, that
is, its ability to use the lowest cost raw material and make the highest value
possible products. The PPI is based on the scale of the operation, conversion
intensity and hydrogen intensity. We maintain models of seven different
refinery configurations on the Gulf Coast of varying degrees of complexity and
type of crude processed. By rating each of these model refineries according to
scale, conversion intensity and hydrogen intensity, we have been able to
develop weighting factors on how each of these contributes to margin.
As shown in Figure VII-6 all but one USGC refinery (excluding small specialty
operations) are significantly better than the LLS cracking refinery (a cracking
refinery with no vacuum bottoms upgrading processing Light Louisiana Sweet
crude oil). This represents a significant portion of the U.S. supply and, thus,
most members of the group must survive in order to meet demand requirements.
This group is shown to have margins about $0.50/bbl. better than the LLS
cracking refinery.
The relative position of the Clark Port Arthur refinery is shown in Figure
VII-6 before and after the coker Upgrade Project. It can be seen that the coker
Upgrade Project will move Clark's refinery at Port Arthur from below the middle
of the group to near the top.
Annual average margins after variable costs for the LLS cracking refinery are
shown in Figure VII-7 During the late 1980s, this refinery had a margin above
variable cost of well over the fixed cost level of about $1.20 per barrel.
Thus, margins were sufficient to support the full cost operation of this type
of facility, including sufficient funds to meet needed capital expenditures.
Following the building boom in conversion capacity in the early 1990s, the
margin for this operation fell below the fixed cost level. However, the margin
on average was sufficient to justify incremental processing. We estimate that a
margin above variable cost of about $0.50 a barrel is needed to justify
incremental processing. This level is sufficient to cover timing risks and
other market uncertainties so that the refiner has an incentive to process the
marginal barrel. Going forward, we believe that this marginal LLS refining
operation will continue to be the marginal source of product on the U.S. Gulf
Coast.
In order to understand the basis for our forecast, it is necessary to look
beyond the annual averages. Commodity pricing of crude oil and products
generates high frequency cycles which must be analyzed to project the evolution
of margins.
Commodity Driven Cycles
The impact of commodity markets on margins is difficult to analyze and is the
subject of controversy. The financial community, which benefits from large
numbers of paper transactions, portrays the commodity markets as merely a
mirror reflecting the industry. On the other hand, many industry participants
believe that the markets are not merely a reflection, but are creating the
image. The demand for paper instruments has an
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<PAGE>
impact on the supply/demand balance just as a demand for physical barrels,
although in the long term, the physical balance must prevail. Commodity markets
greatly increase the number of participants since no physical position or
assets are required, only a credit line.
For refining, the problem is further exacerbated by the fact that most of the
activity is on crude oil rather than on products. The concentration of activity
in crude oil results from its fundability and a smaller risk compared to
refined products. Likewise, producers have a much greater need for hedging
instruments to lock in production profits and loan repayments than do consumers
of refined products. Thus, a large demand for crude oil hedging instruments is
met by speculators, commodity funds, etc. The result is that the crude oil
market can often go in a different direction from product markets depending on
the supply/demand for hedging instruments as opposed to the supply/demand for
physical crude oil.
Commodity markets have made it impossible to have market leadership to
provide discipline in downward cycles to prevent margins from plunging to
levels that shut in marginal production. The international nature of the market
further aggravates the problem by causing imbalances in any part of the world
to quickly spread to all markets. The result is that prices are extremely
sensitive to small changes in the supply/demand balance.
The sensitivity of margins is shown in Figure VII-8. The volatility and
cyclic behavior is apparent in this chart of monthly averages. Daily averages
would show even greater volatility. Cycles in refining are likely to continue
to have very high frequency because of the overall slow growth in demand. That
is, imbalances can quickly be met and, if necessary, modest capital
expenditures can add capacity commensurate with the rate of growth in demand.
By contrast, the chemical industry which is growing at a 4% or 5% rate, shows
longer term cyclic behaviors and capacity shortages may take several years to
work off. Thus, chemicals can enjoy very strong earnings during their upward
cycles for several years.
The average margin only tells part of the story. The peak level margins form
one set of data points while the bottom level another. In addition, a number of
points are intermediate.
Margin Forecast for LLS Cracker
The margin chart (Figure VII-8) can be idealized somewhat as corresponding to
three basic zones of operation. In the "boom" zone, capacity is running full
out, margins are sufficient to attract imports, and the profit for running
incremental crude oil covers fully allocated costs. This level of profitability
would produce very satisfactory returns for the refining industry if it could
be sustained. The "bust" cycle occurs when considerable excess product is
available on the market. In this part of the cycle, runs must be cut to bring
supply/demand back into balance. At this level, a marginal loss occurs on
incremental runs.
The marginal part of the cycle has the highest frequency of occurrence and is
the basis of our theory of incremental supply. At this level of margin, it is
profitable to run incremental crude oil at a marginal profit of about 50c per
barrel. At this level, the risk of holding inventory can be compensated and an
incentive occurs to produce marginal product.
As the supply/demand balance tightens for the reasons discussed previously,
we believe that the frequency of the cycles will change, although their basic
character will not. We anticipate more and longer boom cycles and fewer of the
bust cycles. As capacity tightens, turnarounds, unexpected cold weather, etc.
will have a bigger impact and a greater chance of forcing up margins. From
November 1997 until December 1998 the monthly averages have been above the
"bust" category and there have been a number of data points in the "boom"
category. However, margins weakened in first half of 1999. In the near term,
some downward pressure may result from the full startup of the Trans-American
refinery. After that, we forecast an average trend line at approximately full
cost break-even economics.
Refinery Margins
In Table VII-3 through VII-6, historical and forecast margins and incremental
returns are presented for several USGC refinery configurations in current and
constant 1999 dollars. Capital intensive heavy crude
C-59
<PAGE>
operations show the greatest return. These margins are based on producing fuel
products only. Many refineries also produce lubes, chemicals, and specialty
products. These operations can have a significant impact on profitability in
addition to the basic fuel operations.
USGC PRODUCT PRICES
The USGC product price forecast is shown in Tables VII-7 and VII-8 in current
and constant 1999 dollars, respectively. The prices are spot pipeline lows for
light products and waterborne lows for residual fuel oil. These prices are
developed through an iterative procedure from the forecast margins discussed
above and the product price relationships discussed below.
GASOLINE
The relationship among the gasoline grades and the pricing of oxygenated and
reformulated gasolines through the forecast are important to the economics of
capacity additions and modifications necessary for the industry to be able to
supply these changing fuels. The subsections below describe the basis,
methodology and results for forecasting the prices of the various gasoline
grades.
Conventional Grades
Purvin & Gertz expects conventional gasolines to remain a large part of the
pool throughout the forecast. However, the relationships among the conventional
grades have changed as reformulated fuels were introduced into the pool, since
the value of octane has been modified by the addition of substantial quantities
of MTBE and other oxygenates.
The pricing of different grades of conventional gasoline is a function of the
value of octane. The value of octane is determined by the cost of manufacture.
Our calculations are based on incremental reforming costs. Reforming operations
are the major source of incremental octane in the U.S. refining industry.
Higher octane gasolines are more costly to produce due to higher severity in
the reformer. Higher severity results in lower yields of gasoline, higher
proportions of less valuable by-products and additional operating costs. The
relationship is non-linear and must be determined through calculations of costs
at various levels of severity. The results of this analysis are summarized in
the following table along with the actual market differentials experienced.
CONVENTIONAL GASOLINE OCTANE COSTS AND MAREKT DIFFERENTIALS
(Forecast in 1999 Dollars per Barrel)
<TABLE>
<CAPTION>
1987 1990 1991 1992 1993 1993 1995 1996 1997 2000 2005 2010 2015
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Low Octane
Cost......... 0.20 0.33 0.29 0.23 0.18 0.18 0.20 0.20 0.19 0.13 0.19 0.20 0.19
Market....... 0.21 0.39 0.31 0.27 0.24 0.25 0.24 0.24 0.24 0.17 0.23 0.23 0.23
High Octane
Cost......... 0.29 0.47 0.42 0.33 0.26 0.28 0.28 0.28 0.27 0.19 0.27 0.27 0.27
Market....... 0.35 0.49 0.31 0.34 0.28 0.37 0.33 0.28 0.27 0.25 0.30 0.30 0.30
</TABLE>
In the table above, low octane represents the cost per octane barrel when
producing regular gasoline, while high octane represents the costs when
producing premium gasoline. Cost is based on variable costs of operation and
by-product yields on the USGC. The low octane market value is that implied from
USGC spot market differentials between 70 (R+M)/2 natural gasoline and unleaded
regular. The high octane market value is based on the differential between
unleaded regular and premium gasoline. Historically, there was often a small
market premium above cost. We expect octane values to continue to reflect a
small market add-on versus our estimated cost of manufacture. The premium
should, however, remain modest as all octane costs have been reduced with the
introduction of reformulated fuels.
C-60
<PAGE>
With the introduction of mandated reformulated gasoline, the basis of all
octane values has shifted due to the net effects of addition of MTBE and
modified processing. Addition of MTBE to even a portion of the gasoline pool
results in reduced severity of operations to meet total octane requirements.
This applies to the conventional grade gasoline that is still manufactured and
sold in non-reformulated areas as well as to the reformulated grades.
Reformulated Gasoline
The cost of making reformulated gasoline will vary considerably from refinery
to refinery, but in order to index the spot market spreads, the reformulated
cost differential above conventional gasoline was calculated for our base sour
crude cracking refinery. A summary of the results is shown in the table below.
REFORMULATED/CONVENTIONAL GASOLINE COST DIFFERENTIALS
(Forecast in Constant 1999 Cents/Gallon)
<TABLE>
<CAPTION>
Phase I (1998) Phase II (2000)
-------------- ---------------
<S> <C> <C>
Variable Operating Costs................. 3.60 5.07
Fixed Operating Costs.................... 2.98 3.72
Oxygenate/Yield Credit................... (2.25) (6.17)
Capital Recovery......................... (1.81) 1.49
----- -----
Total.................................. 2.53 4.12
</TABLE>
Our process simulations indicated that it is not very difficult to produce
Phase I reformulated gasoline while at the same time making low sulfur diesel.
Refinery operations needed to be modified only moderately, and the major
investment required and higher operating costs are associated with the
requirement to add oxygenates to regular gasoline. Most refineries have added
MTBE plants based on refinery isobutylenes and adequate supplies of other MTBE
are available for purchase.
The price premiums for Phase I gasoline over conventional gasoline are
calculated to be in the 2.0-2.5c per gallon range under conditions of normal
MTBE prices. In 1995, MTBE prices were inflated early in the year by high
methanol costs, resulting in reformulated fuel premiums peaking in the 6-7c
gallon range. This resulted in an average annual premium on reformulated
gasoline in the 3.5c range for that year. On the other hand, the average spread
in 1997 and 1998 was about 2.5c per gallon and similar levels are projected
until Phase II product is introduced.
Purvin & Gertz expects Phase II reformulated fuels to show premiums of about
4c per gallon versus conventional gasoline. Some additional refinery investment
will be required to meet sulfur, olefins, aromatics, and distillation
restrictions. Many refiners have already added processing which will enable
them to produce Phase I complex model and Phase II reformulated fuels. However,
we believe pricing should reflect some capital recovery for the additional
industry requirements.
DISTILLATE FUELS
Standard Distillate
In this discussion we will refer to typical specification, heating oil/diesel
fuel as "standard distillate," while the 0.05% sulfur diesel fuel introduced in
1993 will be referred to as "low sulfur" diesel. Distillate fuel oil prices are
projected based on a relationship versus unleaded regular standard gasoline.
Distillate price differentials are somewhat more difficult to calculate on a
strict refining economics basis due to the seasonal nature of price trends.
Typically, the summer differentials will rise to a level that more than
supports the maximized conversion of this material to gasoline through revised
cutpoints for FCCU charge. At maximum utilization of cracking capacity, the
differential often rises above balanced levels. Our forecasts are based on a
summertime (second and third quarter) distillate discount averaging in the 5c
per gallon range, though peaks well over this level are typical.
C-61
<PAGE>
Wintertime balances can be erratic and the typical premium on distillate
during the winter season is both a function of the distillate balance, the
weather conditions and the relative strength or weakness of the gasoline
balance. Under typical conditions, we estimate the wintertime premium (first
and last quarters of the year) to be near zero. Often the strongest distillate
period is just prior to the winter as inventories are being added to meet peak
winter requirements. The combination of the expected averages yields a long
term forecast for a 2.5c discount for standard distillates relative to
conventional gasoline on a yearly average basis. From 1992-1996 the average
differentials were narrower than the expected longer term trend. This has
resulted primarily from overcapacity to convert distillates and a weak gasoline
market due to oversupply. In 1997, the spread widened out to over 4.5c as a
result of a mild winter and strong gasoline demand, late in the summer season
(July to September). Product demand growth will absorb the extra capacity and
distillate discounts should return to more normal levels in 1998 and in the
future.
Low Sulfur Diesel
Low sulfur diesel fuel was introduced in the fourth quarter of 1993 to meet
the new EPA requirements for on-highway fuel. This material must have a sulfur
content less than or equal to 0.05%. Pricing of this new fuel can be volatile
on a seasonal basis. Its pricing will be a function of operating costs and
regional supply/demand balances. Based on the production data available, U.S.
refineries are capable of producing more than enough low sulfur diesel to meet
the market's requirements. The premium for this fuel has, therefore, has
remained relatively low, reflecting only variable costs with no fixed cost or
capital recovery.
Based on simulations of refinery operations in each PADD, it appears that
more than enough low sulfur diesel can be produced than is required by
regulation. Therefore, we do not expect refiners to have the opportunity to
earn a return on capital. The price differential should remain close to
variable cost and this expectation has been confirmed over the years since
introduction. Our cost calculations indicate that the low cost supply source
should not be able to recover much more than 1.5c per gallon for low sulfur
diesel relative to the baseline standard fuel. We are assuming that in the long
term, supply capabilities will exceed demand, and this variable cost
differential is used as the long term equilibrium price differential.
RESIDUAL FUEL OIL
We do not envision shortages of low sulfur crude oils in the international
market, and expect that low sulfur fuel oil will continue to be made from low
sulfur crude bottoms and indirect desulfurization/blending. We do not expect
the demand for low sulfur residual fuel oil to be high enough to require
desulfurizing sour vacuum bottoms to produce low sulfur fuel oil in most
markets. Consequently, the differential will be set by the alternative of
additional processing to produce light products rather than fuel oil. This
processing requires significant desulfurization investment and higher operating
costs for sour residuals versus low sulfur residuals. Thus, the differential
between high and low sulfur fuel oil closely follows trends in conversion
returns. When conversion capacity is slack and returns are low, refiners will
maximize income by preferentially processing the lower cost high sulfur
feedstocks, reducing the sweet-sour differential. When capacity is tight,
however, processing low sulfur material can effectively increase capacity due
to its high yields, and so the differential between high and low sulfur
residual widens. The forecast differential is based on continuation of the
observed relationship with the conversion return.
C-62
<PAGE>
TABLE VII-1
INTERNATIONAL CRUDE OIL PRICES
(Current Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Sweet Crude Oil Prices,
$/Bbl.
Brent, FOB............. 17.01 20.64 19.07 12.71 14.46 15.80 19.24 21.40 23.89
Brent, USGC............ 18.38 22.10 20.61 14.11 15.71 17.04 20.64 22.93 25.57
Brent, NWE............. 17.54 21.24 19.68 13.22 14.98 16.36 19.87 22.09 24.65
LLS, St. James......... 18.58 22.31 20.69 14.17 15.90 17.24 20.86 23.18 25.84
WTI Spot, USGC......... 18.61 22.30 20.55 14.38 16.36 17.53 20.82 23.43 26.46
WTI Spot, Cushing...... 18.41 22.13 20.59 14.39 16.33 17.47 20.90 23.54 26.55
WTI Spot, Midland...... 18.28 22.07 20.31 14.12 16.11 17.28 20.54 23.14 26.15
WTI Posted (40 API).... 16.75 20.44 18.62 11.95 13.96 15.47 19.11 21.96 24.86
Sour Crude Oil Prices,
$/Bbl.
Isthmus, FOB........... 16.72 20.58 18.26 12.10 14.03 15.36 18.23 20.28 22.62
Isthmus, USGC.......... 17.40 21.15 18.90 12.58 14.47 15.82 18.70 20.79 23.18
Maya, FOB.............. 14.32 17.26 14.85 8.62 11.50 12.67 13.75 15.31 17.13
Maya, USGC............. 14.96 17.82 15.48 9.10 11.94 13.14 14.25 15.86 17.73
Heavy/Light Differential
WTI Spot, Cushing minus
Maya, FOB............. 4.09 4.87 5.75 5.76 4.83 4.79 7.15 8.22 9.42
</TABLE>
C-63
<PAGE>
TABLE VII-2
INTERNATIONAL CRUDE OIL PRICES
(Forecast in 1999 Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Sweet Crude Oil Prices,
$/Bbl.
Brent, FOB............. 17.01 20.64 19.07 12.71 14.46 15.56 17.17 17.29 17.49
Brent, USGC............ 18.38 22.10 20.61 14.11 15.71 16.79 18.42 18.53 18.71
Brent, NWE............. 17.54 21.24 19.68 13.22 14.98 16.12 17.73 17.86 18.05
LLS, St. James......... 18.58 22.31 20.69 14.17 15.90 16.99 18.62 18.73 18.92
WTI Spot, USGC......... 18.61 22.30 20.55 14.38 16.36 17.27 18.58 18.94 19.37
WTI Spot, Cushing...... 18.41 22.13 20.59 14.39 16.33 17.21 18.65 19.02 19.43
WTI Spot, Midland...... 18.28 22.07 20.31 14.12 16.11 17.02 18.33 18.70 19.14
WTI Posted (40 API).... 16.75 20.44 18.62 11.95 13.96 15.24 17.05 17.75 18.20
Sour Crude Oil Prices,
$/Bbl.
Isthmus, FOB........... 16.72 20.58 18.26 12.10 14.03 15.13 16.27 16.39 16.56
Isthmus, USGC.......... 17.40 21.15 18.90 12.58 14.47 15.58 16.69 16.80 16.97
Maya, FOB.............. 14.32 16.26 14.85 8.62 11.50 12.49 12.27 12.38 12.54
Maya, USGC............. 14.96 17.82 15.48 9.10 11.94 12.95 12.72 12.82 12.98
Heavy/Light Differential
WTI Spot, Cushing minus
Maya, FOB............. 4.09 4.87 5.75 5.76 4.83 4.72 6.38 6.64 6.89
</TABLE>
C-64
<PAGE>
TABLE VII-3
U.S. GULF COAST LIGHT SWEET CRUDE MARGINS
(Current Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
------ ------ ------ ----- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Light Sweet Crude Cost... 18.67 22.31 20.69 14.17 15.90 17.24 20.86 23.18 25.84
Light Sweet Hydroskimming
Refinery
Product Sales
Realization........... 18.32 22.24 20.73 14.84 15.89 17.51 21.11 23.44 26.13
Variable Costs......... 0.30 0.40 0.40 0.36 0.36 0.38 0.40 0.44 0.51
Fixed Costs............ 0.61 0.60 0.62 0.64 0.67 0.66 0.73 0.80 0.89
Net Refining Margin.... (1.27) (1.07) (0.98) (0.34) (1.04) (0.77) (0.88) (0.98) (1.10)
Interest on Working
Capital............... 0.12 0.14 0.13 0.09 0.09 0.10 0.12 0.13 0.15
Return, % of
Replacement Cost...... (17.93) (15.56) (14.15) (5.45) (14.32) (10.87) (11.16) (11.32) (11.50)
Light Sweet Cracking
Refinery
Product Sales
Realization........... 19.93 23.76 22.60 16.16 17.31 18.94 23.05 25.60 28.54
Variable Costs......... 0.46 0.54 0.55 0.52 0.52 0.54 0.57 0.64 0.72
Fixed Costs............ 1.25 1.24 1.28 1.32 1.37 1.35 1.49 1.64 1.82
Net Refining Margin.... (0.46) (0.33) 0.09 0.15 (0.48) (0.20) 0.13 0.14 0.16
Interest on Working
Capital............... 0.13 0.15 0.14 0.10 0.10 0.11 0.13 0.14 0.16
Return, % of
Replacement Cost...... (3.82) (3.06) (0.35) 0.34 (3.66) (1.90) 0.00 0.00 0.00
Light Sweet Coking
Refinery
Product Sales
Realization........... 20.48 24.46 23.30 16.63 17.80 19.49 23.90 26.54 29.57
Variable Costs......... 0.51 0.59 0.60 0.57 0.57 0.59 0.63 0.69 0.78
Fixed Costs............ 1.48 1.47 1.52 1.57 1.62 1.61 1.77 1.96 2.16
Net Refining Margin.... (0.18) 0.09 0.49 0.33 (0.30) 0.05 0.64 0.71 0.79
Interest on Working
Capital............... 0.14 0.15 0.15 0.10 0.10 0.11 0.13 0.15 0.16
Return, % of
Replacement Cost...... (1.74) (0.34) 1.86 1.23 (2.16) (0.32) 2.43 2.44 2.45
Light Sweet Incremental
Capital.................
Recovery Factors (%)
Hydroskimming/Cracking. 10.45 9.57 13.60 6.22 7.11 7.17 11.28 11.45 11.63
Cracking/Coking........ 10.49 15.74 14.92 6.55 6.74 9.01 16.72 16.80 16.88
</TABLE>
C-65
<PAGE>
TABLE VII-4
U.S. GULF COAST LIGHT SWEET CRUDE MARGINS
(Forecast in 1999 Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
------ ------ ------ ----- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Light Sweet Crude Cost... 18.67 22.31 20.69 14.17 15.90 16.99 18.62 18.73 18.92
Light Sweet Hydroskimming
Refinery
Product Sales
Realization........... 18.32 22.24 20.73 14.84 15.89 17.25 18.84 18.94 19.13
Variable Costs......... 0.30 0.40 0.40 0.36 0.36 0.38 0.35 0.36 0.37
Fixed Costs............ 0.61 0.60 0.62 0.64 0.67 0.65 0.65 0.65 0.65
Net Refining Margin.... (1.27) (1.07) (0.98) (0.34) (1.04) (0.76) (0.78) (0.79) (0.81)
Interest on Working
Capital............... 0.12 0.14 0.13 0.09 0.09 0.10 0.11 0.11 0.11
Return, % of
Replacement Cost...... (17.93) (15.56) (14.15) (5.45) (14.32) (10.87) (11.16) (11.32) (11.50)
Light Sweet Cracking
Refinery
Product Sales
Realization........... 19.93 23.76 22.60 16.16 17.31 18.66 20.57 20.69 20.89
Variable Costs......... 0.46 0.54 0.55 0.52 0.52 0.53 0.51 0.51 0.53
Fixed Costs............ 1.25 1.24 1.28 1.32 1.37 1.33 1.33 1.33 1.33
Net Refining Margin.... (0.46) (0.33) 0.09 0.15 (0.48) (0.19) 0.12 0.12 0.12
Interest on Working
Capital............... 0.13 0.15 0.14 0.10 0.10 0.11 0.12 0.12 0.12
Return, % of
Replacement Cost...... (3.82) (3.06) (0.35) 0.34 (3.66) (1.90) 0.00 0.00 0.00
Light Sweet Coking
Refinery
Product Sales
Realization........... 20.48 24.46 23.30 16.63 17.80 19.20 21.33 21.45 21.65
Variable Costs......... 0.51 0.59 0.60 0.57 0.57 0.58 0.56 0.56 0.57
Fixed Costs............ 1.48 1.47 1.52 1.57 1.62 1.58 1.58 1.58 1.58
Net Refining Margin.... (0.18) 0.09 0.49 0.33 (0.30) 0.05 0.57 0.57 0.58
Interest on Working
Capital............... 0.14 0.15 0.15 0.10 0.10 0.11 0.12 0.12 0.12
Return, % of
Replacement Cost...... (1.74) (0.34) 1.86 1.23 (2.16) (0.32) 2.43 2.44 2.45
Light Sweet Incremental
Capital Recovery Factors
(%)
Hydroskimming/Cracking. 10.45 9.57 13.60 6.22 7.11 7.17 11.28 11.45 11.63
Cracking/Coking........ 10.49 15.74 14.92 6.55 6.74 9.01 16.72 16.80 16.88
</TABLE>
C-66
<PAGE>
TABLE VII-5
U.S. GULF COAST SOUR CRUDE MARGINS
(Current Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
------ ------ ------ ----- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Light Sour Crude Cost.... 17.40 21.15 18.90 12.58 14.47 15.82 18.70 20.79 23.18
Light Sour Hydroskimming
Refinery
Product Sales
Realization........... 17.12 20.27 18.95 13.24 14.80 16.05 18.60 20.66 23.06
Variable Costs......... 0.36 0.47 0.48 0.43 0.43 0.45 0.47 0.52 0.60
Fixed Costs............ 0.82 0.81 0.84 0.87 0.90 0.89 0.98 1.08 1.20
Net Refining Margin.... (1.46) (2.16) (1.26) (0.64) (1.01) (1.11) (1.56) (1.73) (1.91)
Interest on Working
Capital............... 0.12 0.14 0.13 0.09 0.09 0.10 0.11 0.13 0.14
Return, % of
Replacement Cost...... (15.17) (21.96) (13.11) (6.80) (10.29) (11.15) (13.88) (13.97) (13.98)
Light Sour Cracking
Refinery
Product Sales
Realization........... 18.62 21.95 20.87 14.76 16.13 17.53 20.79 23.10 25.76
Variable Costs......... 0.62 0.78 0.79 0.72 0.73 0.76 0.80 0.88 1.01
Fixed Costs............ 1.49 1.48 1.53 1.58 1.64 1.62 1.78 1.97 2.18
Net Refining Margin (0.89) (1.46) (0.34) (0.13) (0.70) (0.67) (0.49) (0.55) (0.60)
Interest on Working
Capital............... 0.13 0.15 0.14 0.10 0.10 0.11 0.12 0.14 0.15
Return, % of
Replacement Cost...... (5.44) (8.52) (2.52) (1.16) (4.14) (3.96) (2.84) (2.85) (2.85)
Light Sour Coking
Refinery
Product Sales
Realization........... 19.63 23.44 22.32 15.94 17.07 18.67 22.89 25.41 28.32
Variable Costs......... 0.71 0.88 0.89 0.82 0.83 0.86 0.91 1.00 1.15
Fixed Costs............ 1.92 1.90 1.97 2.03 2.10 2.08 2.29 2.53 2.80
Net Refining Margin (0.40) (0.50) 0.56 0.51 (0.34) (0.09) 0.98 1.09 1.20
Interest on Working
Capital............... 0.14 0.15 0.15 0.10 0.10 0.11 0.13 0.15 0.16
Return, % of
Replacement Cost (2.20) (2.66) 1.67 1.62 (1.76) (0.79) 3.02 3.02 3.01
Maya Coking Refinery
Product Sales
Realization........... 19.33 22.85 22.02 15.73 16.84 18.32 22.37 24.84 27.68
Variable Costs......... 1.19 1.52 1.54 1.40 1.40 1.47 1.54 1.71 1.95
Fixed Costs............ 2.42 2.40 2.48 2.55 2.65 2.62 2.89 3.19 3.52
Net Refining Margin 0.76 1.11 2.53 2.68 0.84 1.09 3.69 4.08 4.47
Interest on Working
Capital............... 0.13 0.14 0.14 0.09 0.10 0.11 0.12 0.13 0.15
Return, % of
Replacement Cost...... 2.04 3.12 7.60 8.19 2.35 3.07 9.99 9.99 9.92
Light Sour Incremental
Capital Recovery Factors
(%)
Hydroskimming/Cracking. 6.75 8.26 10.75 5.94 3.56 5.05 10.98 11.08 11.08
Cracking/Coking........ 8.85 17.29 15.98 11.13 6.38 10.00 23.00 23.00 23.00
Maya Coking/Coking..... 17.77 24.57 29.63 32.60 17.60 17.37 35.85 35.87 35.55
</TABLE>
C-67
<PAGE>
TABLE VII-6
U.S. GULF COAST SOUR CRUDE MARGINS
(Forecast in 1999 Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
------ ------ ------ ----- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Light Sour Crude Cost... 17.40 21.15 18.90 12.58 14.47 15.58 16.69 16.80 16.97
Light Sour Hydroskimming
Refinery
Product Sales
Realization.......... 17.12 20.27 18.95 13.24 14.80 15.81 16.59 16.70 16.88
Variable Costs........ 0.36 0.47 0.48 0.43 0.43 0.44 0.42 0.42 0.44
Fixed Costs........... 0.82 0.81 0.84 0.87 0.90 0.88 0.88 0.88 0.88
Net Refining Margin... (1.46) (2.16) (1.26) (0.64) (1.01) (1.09) (1.39) (1.40) (1.40)
Interest on Working
Capital.............. 0.12 0.14 0.13 0.09 0.09 0.10 0.10 0.10 0.10
Return, % of
Replacement Cost..... (15.17) (21.96) (13.11) (6.80) (10.29) (11.15) (13.88) (13.97) (13.98)
Light Sour Cracking
Refinery
Product Sales
Realization.......... 18.62 21.95 20.87 14.76 16.13 17.27 18.55 18.67 18.86
Variable Costs........ 0.62 0.78 0.79 0.72 0.73 0.75 0.71 0.71 0.74
Fixed Costs........... 1.49 1.48 1.53 1.58 1.64 1.59 1.59 1.59 1.59
Net Refining Margin... (0.89) (1.46) (0.34) (0.13) (0.70) (0.66) (0.44) (0.44) (0.44)
Interest on Working
Capital.............. 0.13 0.15 0.14 0.10 0.10 0.11 0.11 0.11 0.11
Return, % of
Replacement Cost..... (5.44) (8.52) (2.52) (1.16) (4.14) (3.96) (2.84) (2.85) (2.85)
Light Sour Coking
Refinery
Product Sales
Realization.......... 19.63 23.44 22.32 15.94 17.07 18.39 20.42 20.54 20.73
Variable Costs........ 0.71 0.88 0.89 0.82 0.83 0.85 0.81 0.81 0.84
Fixed Costs........... 1.92 1.90 1.97 2.03 2.10 2.05 2.05 2.05 2.05
Net Refining Margin... (0.40) (0.50) 0.56 0.51 (0.34) (0.09) 0.88 0.88 0.88
Interest on Working
Capital.............. 0.14 0.15 0.15 0.10 0.10 0.11 0.12 0.12 0.12
Return, % of
Replacement Cost..... (2.20) (2.66) 1.67 1.62 (1.76) (0.79) 3.02 3.02 3.01
Maya Coking Refinery
Product Sales
Realization.......... 19.33 22.85 22.02 15.73 16.84 18.05 19.96 20.07 20.26
Variable Costs........ 1.19 1.52 1.54 1.40 1.40 1.45 1.37 1.38 1.43
Fixed Costs........... 2.42 2.40 2.48 2.55 2.65 2.58 2.58 2.58 2.58
Net Refining Margin... 0.76 1.11 2.53 2.68 0.84 1.07 3.29 3.29 3.27
Interest on Working
Capital.............. 0.13 0.14 0.14 0.09 0.10 0.10 0.11 0.11 0.11
Return, % of
Replacement Cost..... 2.04 3.12 7.60 8.19 2.35 3.07 9.99 9.99 9.92
Light Sour Incremental
Capital Recovery
Factors (%)
Hydroskimming
Cracking............. 6.75 8.26 10.75 5.94 3.56 5.05 10.98 11.08 11.08
Cracking/Coking....... 8.85 17.29 15.98 11.13 6.38 10.00 23.00 23.00 23.00
Maya Coking/Coking.... 17.77 24.57 29.63 32.60 17.60 17.37 35.85 35.87 35.55
</TABLE>
C-68
<PAGE>
TABLE VII-7
U.S. PRODUCT PRICES
(Current Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gulf Coast Product
Prices, (c/Gal.)
Propane................ 31.89 41.98 37.20 25.87 28.35 31.08 37.66 42.46 48.25
Isobutane.............. 40.43 50.56 46.37 31.70 35.37 37.58 46.42 51.19 56.84
Normal Butane.......... 38.19 46.94 43.68 30.76 33.95 35.66 41.36 45.57 50.59
Natural Gasoline....... 40.55 49.50 47.75 33.78 35.78 39.61 47.44 52.59 58.87
Premium Unleaded
Gasoline.............. 55.44 63.37 62.20 45.34 48.05 51.45 63.47 70.44 78.32
Mid-grade Unleaded
Gasoline.............. 52.17 60.61 59.66 42.73 45.47 48.88 60.04 66.63 74.17
Regular Unleaded
Gasoline.............. 50.72 59.37 58.34 41.17 44.08 47.84 58.62 65.05 72.46
Jet/Kerosene........... 49.31 60.52 55.75 40.20 43.15 47.84 58.62 65.05 72.46
Diesel/No. 2 Fuel Oil.. 47.07 58.20 53.60 37.55 40.60 45.30 55.82 61.96 69.04
0.05% S Diesel......... 48.51 59.66 54.68 39.30 42.20 46.54 57.49 63.82 71.13
1% Sulfur Residual Fuel
Oil ($/Bbl.).......... 14.56 17.35 16.01 11.96 12.63 13.76 15.23 16.94 18.93
3% Sulfur Residual Fuel
Oil................... 13.62 15.41 14.26 9.49 11.62 12.29 12.36 13.78 15.44
Reformulated Gasoline
(c/Gal.)
Phase I 1996-1999,
Phase II
2000-2015
Premium Unleaded
Gasoline.............. 58.90 65.66 64.68 47.10 49.53 54.39 66.73 74.48 83.68
Mid-grade Unleaded
Gasoline.............. 55.72 62.88 62.16 44.95 47.37 52.23 63.30 70.67 79.52
Regular Unleaded
Gasoline.............. 54.31 61.64 60.82 43.69 46.17 51.24 61.89 69.09 77.81
</TABLE>
C-69
<PAGE>
TABLE VII-8
U.S. PRODUCT PRICES
(Forecast in 1999 Dollars per Barrel)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 2000 2005 2010 2015
----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gulf Coast Product
Prices, (c/Gal.)
Propane................ 31.89 41.98 37.20 25.87 28.35 30.62 33.60 34.31 35.32
Isobutane.............. 40.43 50.56 46.37 31.70 35.37 37.03 41.42 41.37 41.61
Normal Butane.......... 38.19 46.94 43.68 30.76 33.95 35.14 36.90 36.83 37.04
Natural Gasoline....... 40.55 49.50 47.75 33.78 35.78 39.03 42.33 42.50 43.10
Premium Unleaded
Gasoline.............. 55.44 63.37 62.20 45.34 48.05 50.69 56.63 56.93 57.33
Mid-grade Unleaded
Gasoline.............. 52.17 60.61 59.66 42.73 45.47 48.16 53.57 53.85 54.29
Regular Unleaded
Gasoline.............. 50.72 59.37 58.34 41.17 44.08 47.13 52.31 52.58 53.04
Jet/Kerosene........... 49.31 60.52 55.75 40.20 43.15 47.13 52.31 52.58 53.04
Diesel/No. 2 Fuel Oil.. 47.07 58.20 53.60 37.55 40.60 44.63 49.81 50.08 50.54
0.05% S Diesel......... 48.51 59.66 54.68 39.30 42.20 45.85 51.30 51.58 52.07
1% Sulfur Residual Fuel
Oil ($/Bbl.).......... 14.56 17.35 16.01 11.96 12.63 13.56 13.59 13.69 13.86
3% Sulfur Residual Fuel
Oil ($/Bbl.).......... 13.62 15.41 14.26 9.49 11.62 12.11 11.03 11.13 11.30
Reformulated Gasoline
(c/Gal.)
Phase I 1996-1999,
Phase II 2000-2015
Premium Unleaded
Gasoline.............. 58.90 65.66 64.68 47.10 49.53 53.59 59.54 60.20 61.25
Mid-grade Unleaded
Gasoline.............. 55.72 62.88 62.16 44.95 47.37 51.45 56.48 57.11 58.21
Regular Unleaded
Gasoline.............. 54.31 61.64 60.82 43.69 46.17 50.49 55.22 55.84 56.96
</TABLE>
C-70
<PAGE>
$255,000,000
Port Arthur Finance Corp.
Offer to Exchange All Outstanding 12.50% Senior Secured Notes due 2009 for
12.50% Senior Secured Notes due 2009, which have been registered under the
Securities Act of 1933.
Unconditionally Guaranteed Jointly and Severally by Port Arthur Coker Company
L.P., Sabine River Holding Corp. and Neches River Holding Corp.
Until , 2000, (90 days after the date of this prospectus), all dealers
effecting transactions in the exchange notes, whether or not participating in
this distribution, may be required to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments of subscriptions.
<PAGE>
PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS
Item 20. Indemnification of Directors and Officers.
Section 145 of the General Corporation Law of the State of Delaware (the
"Delaware Law") authorizes the registrants to indemnify their officers and
directors under certain circumstances and subject to certain conditions and
limitations as stated therein, against all expenses and liabilities incurred by
or imposed upon them as a result of actions, suits and proceedings, civil or
criminal, brought against them as such officers and directors if they acted in
good faith and in a manner they reasonably believed to be in or not opposed to
the best interests of the registrants and, with respect to any criminal action
or proceeding, had no reasonable cause to believe their conduct was unlawful.
Reference is hereby made to Article 11 of the Certificate of Incorporation of
Port Arthur Finance and Article 10 of the Amended and Restated Certificates of
Incorporation of Sabine River and Neches River, copies of which are filed as
Exhibits 3.01(a), 3.01(b) and 3.01(c), respectively, each of which provides for
indemnification of officers and directors to the fullest extent permitted by
Delaware Law. Reference is hereby made to Section 7.1 of the By Laws of Port
Arthur Finance and Section 7.1 of the Amended and Restated By Laws of each of
Sabine River and Neches River, copies of which are filed as Exhibits 3.02(a),
3.02(b) and 3.02(c), respectively, each of which provides for indemnification
of directors or officers in derivative and non derivative actions in the
circumstances provided in such Section 7.1. Section 7.2 of the By Laws of Port
Arthur Finance and Section 7.2 of the Amended and Restated By Laws of each of
Sabine River and Neches River authorize each such company to purchase and
maintain insurance on behalf of any director, officer, employee or agent of
such company against any liability asserted against or incurred by them in such
capacity or arising out of their status as such, whether or not such company
would have the power to indemnify such person against such liability.
Sabine River Holdings Corp. maintains a directors' and officers' insurance
policy which insures the officers and directors of Sabine River and its
subsidiaries from any claim arising out of an alleged wrongful act by such
persons in their respective capacities as officers and directors.
Section 102(b)(7) of the Delaware Law permits corporations to eliminate or
limit the personal liability of a director to the corporation or its
stockholders for monetary damages for breach of a fiduciary duty of care as a
director. Reference is made to Article 10 of Port Arthur Finance's Certificate
of Incorporation and Article 9 of the Amended and Restated Certificates of
Incorporation of each of Sabine River and Neches River each of which limit a
director's liability in accordance with such Section.
Reference is made to Section 7 of the Purchase Agreement, copy of which is
filed as Exhibit 1.01 for information concerning indemnification arrangements
among the registrants and the initial purchasers of the outstanding notes.
Item 21. Exhibits and Financial Statement Schedules
(a) Exhibits
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
* 1.01 --Purchase Agreement, dated as of August 10, 1999 among Credit
Suisse First Boston Corporation, Goldman, Sachs & Co., Deutsche
Bank Securities Inc., Clark Refining Holdings Inc., Port Arthur
Finance Corp. ("PAFC"), Port Arthur Coker Company L.P.
("PACC"), Sabine River Holding Corp. ("Sabine") and Neches
River Holding Corp. ("Neches").
* 3.01(a) --Certificate of Incorporation of PAFC
* 3.01(b) --Amended and Restated Certificate of Incorporation of Sabine and
the Certificate of Amendment thereto dated August 11, 1999
</TABLE>
II-1
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
* 3.01(c) --Amended and Restated Certificate of Incorporation of Neches and
the Certificate of Amendment thereto dated August 11, 1999
* 3.02(a) --By Laws of PAFC
* 3.02(b) --Amended and Restated By Laws of Sabine
* 3.02(c) --Amended and Restated By Laws of Neches
* 3.03 --Amended and Restated Partnership Agreement of Port Arthur Coker
Company L.P., dated as of August 2, 1999, among Sabine and Neches
* 4.01 --Indenture, dated as of August 19, 1999, among PAFC, PACC, Sabine,
Neches, HSBC Bank USA, the capital markets trustee and Bankers
Trust Company, as Collateral Trustee;
* 4.02 --Form of 12.50% Senior Secured Notes due 2009 (the "Exchange Note")
(included as part of Exhibit 4.01 hereto)
* 4.03 --Registration Rights Agreement, dated as of August 19, 1999, among
Credit Suisse First Boston Corporation, Goldman, Sachs & Co.,
Deutsche Bank Securities Inc., Clark Refining Holdings Inc., PAFC,
PACC, Sabine and Neches
* 4.04 --Common Security Agreement, dated as of August 19, 1999, among
PAFC, PACC, Sabine, Neches, 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
* 4.05 --Transfer Restrictions Agreement, dated as of August 19, 1999,
among PAFC, PACC, Clark Refining Holdings Inc., Sabine, Neches,
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 ("BCIP 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
* 4.06 --Intercreditor Agreement, dated as of August 19, 1999, among
Bankers Trust Company, as Collateral Trustee, Deutshe Bank, as
Administrative Agent, Winterthur, as Oil Payment Insurers
Administrative Agent and Debt Service Reserve Insurer and HSBC
Bank, as Capital Markets Trustee
* 5.01 --Opinion of Simpson Thacher & Bartlett as to the legality of the
securities being registered
*10.01 --Capital Contribution Agreement, dated as of August 19, 1999, among
BCP III, BOCP III, BCIP, Clark Refining Holdings Inc.. PACC,
Sabine, Neches and Bankers Trust Company as Collateral Trustee
*10.02 --Capital Contribution Agreement, dated as of August 19, 1999, by
and among Occidental Petroleum Corporation, Clark Refining
Holdings, Inc., PACC, Sabine, Neches and Bankers Trust Company as
Collateral Trustee
*10.03 --Bank Senior Loan Agreement, dated as of August 19, 1999, among
PAFC, PACC, Sabine, Neches, Deutsche Bank, as Administrative Agent
and the Bank Senior Lenders named therein
*10.04 --Secured Working Capital Facility, dated as of August 19, 1999,
among PAFC, PACC, Sabine, Neches, Deutsche Bank, as Administrative
Agent and the Bank Senior Lenders named therein
*10.05 --Reimbursement Agreement, dated as of August 19, 1999, among PAFC,
PACC, Sabine, Neches and Winterthur, as Primary Insurer and Oil
Payment Insurers Administrative Agent
</TABLE>
II-2
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
*10.06 --Engineering, Procurement and Construction Contract, dated as of July
12, 1999, between PACC and Foster Wheeler USA Corporation
*10.07 --EPC Contract Parent Guarantee, dated as of July 13, 1999, between
PACC and Foster Wheeler Corporation
*10.8 --Services and Supply Agreement, dated as of August 19, 1999, between
PACC and Clark R&M
*10.9 --Product Purchase Agreement, dated as of August 19, 1999, between
PACC and Clark R&M
*10.10 --Hydrogen Supply Agreement, dated as of August 1, 1999, between PACC
and Air Products and Chemicals, Inc.
*10.11 --Coker Complex Ground Lease, dated as of August 19, 1999, between
PACC and Clark R&M
*10.12 --Ancillary Equipment Site Lease, dated as of August 19, 1999, between
PACC and Clark R&M
*10.13 --Assignment and Assumption Agreement, dated as of August 19, 1999,
between PACC and Clark R&M
*10.14 --Maya Crude Oil Sale Agreement, dated as of March 10, 1998, between
Clark R&M and P.M.I. Comercio Internacional, S.A. de C.V., as
amended by the First Amendment and Supplement to the Maya Crude Oil
Sales Agreement, dated as of August 19, 1999 (included as Exhibit
10.15 hereto), and as assigned by Clark R&M to PACC pursuant to the
Assignment and Assumption Agreement, dated as of August 19, 1999
(included as Exhibit 10.13 hereto.
*10.15 --First Amendment and Supplement to the Maya Crude Oil Sales
Agreement, dated as of August 19, 1999
*10.16 --Guarantee Agreement, dated as of March 10, 1998, between Clark R&M
and Petroleos Mexicanos, the Mexican national oil company, as
assigned by Clark R&M to PACC as of August 19, 1999 pursuant to the
Assignment and Assumption Agreement, dated as of August 19, 1999
(included as Exhibit 10.13)
*15 --Letter Regarding Unaudited Interim Financial Information
*21 --Subsidiaries of the Registrants
*23.01 --Consent of Simpson Thacher & Bartlett (contained in Exhibit 5.01)
**23.02 --Consent of Deloitte & Touche LLP
**23.03 --Consent of Purvin & Gertz, Inc.
*23.04 --Consent of PricewaterhouseCoopers LLP
*25 --Form T-1 Statement of Eligibility under the Trust Indenture Act of
1939 of HSBC Bank USA, as trustee
*99.01 --Form of Letter of Transmittal
*99.02 --Form of Notice of Guaranteed Delivery
</TABLE>
- --------
* Previously filed.
** Filed herewith.
II-3
<PAGE>
(b) Financial Statement Schedules
Item 22. Undertakings
(a) The undersigned registrants hereby undertake to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
(b) Insofar as indemnification for liabilities arising under Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrants pursuant to the foregoing provisions, or otherwise, the registrants
have been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the applicable registrant will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the final
adjudication of such issue.
(c) The undersigned registrants hereby undertake:
(1) To file, during any period in which offers or sales are being made,
a post-effective amendment to this registration statement:
(i)to include any prospectus required by Section 10(a)(3) of the
Securities Act;
(ii)to reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set
forth in the registration statement. Notwithstanding the foregoing,
any increase or decrease in volume of securities offered (if the
total dollar value of securities offered would not exceed that which
was registered) and any deviation from the low or high end of the
estimated maximum offering range may be reflected in the form of
prospectus filed with the Commission pursuant to Rule 424(b) if, in
the aggregate, the changes in volume and price represent no more
that a 20 percent change in the maximum aggregate offering price set
forth in the "Calculation of Registration Fee" table in the
effective registration statement; and
(iii)to include any material information with respect to the plan of
distribution not previously disclosed in the registration statement
or any material change to such information in the registration
statement;
(2) That, for the purpose of determining any liability under the
Securities Act, each such post-effective amendment shall be deemed to
be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof; and
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.
II-4
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant issuer has duly caused this amended registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the city
of St. Louis, state of Missouri, on April 4, 2000.
PORT ARTHUR FINANCE CORP.
/s/ William C. Rusnack
By:____________________________
Name: William C. Rusnack
Title: President and CEO
Pursuant to the requirements of the Securities Act of 1933, as amended, this
amended registration statement has been signed on April 4, 2000 by or behalf of
the following persons in the capacities indicated with the registrant issuer.
Signatures Title
* Director, President
- ------------------------------------- and CEO
William C. Rusnack (Principal Executive
Officer)
Executive Vice
* President and Chief
- ------------------------------------- Financial Officer
Maura J. Clark
(Principal Financial
Officer)
* Vice President,
- ------------------------------------- Controller and
Dennis R. Eichholz Treasurer
(Principal Accounting
Officer)
* Director
- -------------------------------------
Robert L. Friedman
II-5
<PAGE>
Signatures Title
* Director
- -------------------------------------
David I. Foley
* Director
- -------------------------------------
Stephen I. Chazen
* Director
- -------------------------------------
William E. Haynes
/s/ Richard A. Keffer
*By:_________________________________
Richard A. Keffer
Attorney-in-Fact
II-6
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant guarantor has duly caused this amended registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the city
of St. Louis, state of Missouri, on April 4, 2000.
PORT ARTHUR COKER COMPANY L.P.
By: Sabine River Holding Corp.,
as General Partner
/s/ William C. Rusnack
By: _________________________________
Name: William C. Rusnack
Title: President and CEO
Pursuant to the requirements of the Securities Act of 1933, as amended, this
amended registration statement has been signed on April 4, 2000 by or behalf of
the following persons in the capacities indicated with the registrant
guarantor.
Signatures Title
* Director
- -------------------------------------
William C. Rusnack
* Director
- -------------------------------------
Rober L. Friedman
* Director
- -------------------------------------
David I. Foley
* Director
- -------------------------------------
Stephen I. Chazen
* Director
- -------------------------------------
William E. Haynes
/s/ Richard A. Keffer
*By:_________________________________
Richard A. Keffer
Attorney-in-Fact
II-7
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant guarantor has duly caused this amended registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the city
of St. Louis, state of Missouri, on April 4, 2000.
SABINE RIVER HOLDING CORP.
/s/ William C. Rusnack
By ______________________________
Name: William C. Rusnack
Title: President and CEO
Pursuant to the requirements of the Securities Act of 1933, as amended, this
amended registration statement has been signed on April 4, 2000 by or behalf of
the following persons in the capacities indicated with the registrant
guarantor.
Signatures Title
* Director, President
- ------------------------------------- and CEO
William C. Rusnack (Principal Executive
Officer)
Executive Vice
* President and Chief
- ------------------------------------- Financial Officer
Maura J. Clark
(Principal Financial
Officer)
* Vice President,
- ------------------------------------- Controller and
Dennis R. Eichholz Treasurer
(Principal Accounting
Officer)
* Director
- -------------------------------------
Robert L. Friedman
II-8
<PAGE>
Signatures Title
* Director
- -------------------------------------
David I. Foley
* Director
- -------------------------------------
Stephen I. Chazen
* Director
- -------------------------------------
William E. Haynes
/s/ Richard A. Keffer
*By:_________________________________
Richard A. Keffer
Attorney-in-Fact
II-9
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant guarantor has duly caused this amended registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the city
of St. Louis, state of Missouri, on April 4, 2000.
NECHES RIVER HOLDING CORP.
/s/ William C. Rusnack
By:_____________________________
Name: William C. Rusnack
Title: President and CEO
Pursuant to the requirements of the Securities Act of 1933, as amended, this
amended registration statement has been signed on April 4, 2000 by or behalf of
the following persons in the capacities indicated with the registrant
guarantor.
Signatures Title
* Director, President
- ------------------------------------- and CEO
William C. Rusnack (Principal Executive
Officer)
Executive Vice
* President and Chief
- ------------------------------------- Financial Officer
Maura J. Clark
(Principal Financial
Officer)
* Vice President,
- ------------------------------------- Controller and
Dennis R. Eichholz Treasurer
(Principal Accounting
Officer)
* Director
- -------------------------------------
Rober L. Friedman
* Director
- -------------------------------------
David I. Foley
* Director
- -------------------------------------
Stephen I. Chazen
* Director
- -------------------------------------
William E. Haynes
/s/ Richard A. Keffer
*By: ________________________________
Richard A. Keffer Attorney-in-Fact
II-10
<PAGE>
Exhibit 23.02
INDEPENDENT AUDITORS' CONSENT
We consent to the use in this Amendment No. 2 to Registration Statement No.
333-92871 of Port Arthur Finance Corp. of our reports dated March 2, 2000,
appearing in the Prospectus related to the consolidated financial statements of
Port Arthur Coker Company L.P. and Subsidiary and Sabine River Holding Corp.
and Subsidiaries, which are part of such Registration Statement, and to the
reference to us under the headings "Selected Consolidated Financial Data" and
"Experts" in such Prospectus.
/s/ Deloitte & Touche LLP
April 4, 2000
<PAGE>
Exhibit 23.03
[PURVIN & GERTZ, INC. LETTERHEAD OF KEN E. NOACK, SENIOR PRINCIPAL]
April 3, 2000
CONSENT OF PURVIN & GERTZ, INC.
We hereby consent to the use in the Prospectus constituting part of the
amended Registration Statement on Form S-4 of Port Arthur Finance Corp. of our
Independent Engineer's Report on the Port Arthur Coker Company Project in its
entirety, dated August 10, 1999, and our Crude Oil and Refined Market Forecast
in its entirety, prepared for Port Arthur Coker Company L.P., dated July 13,
1999, which appear in such Prospectus and to the references to our firm in such
Prospectus.
PURVIN & GERTZ, INC.
/s/ Ken E. Noack
------------------
Ken E. Noack
