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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2001
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 333-92871-02
SABINE RIVER HOLDING CORP.
(Exact name of registrant as specified in its charter)
Delaware 43-1857408
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1801 S. Gulfway Drive
Office No. 36 77640
Port Arthur, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (409) 982-7491
Indicate by check mark whether the registrant:(1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ___
---
Number of shares of registrant's common stock, $.01 par value, outstanding
as of October 31, 2001: 6,818,182
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Sabine River Holding Corp.
Form 10-Q
September 30, 2001
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Independent Accountants' Report ................................. 1
Consolidated Balance Sheets as of December 31, 2000 and
September 30, 2001 ............................................. 2
Consolidated Statements of Operations for the Three- and
Nine-Month Periods Ended September 30, 2000 and 2001 ........... 3
Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2000 and 2001 .................................... 4
Notes to Consolidated Financial Statements ...................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................... 11
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K ................................ 21
Signature ....................................................... 22
FORM 10-Q - PART I
ITEM 1. FINANCIAL STATEMENTS
INDEPENDENT ACCOUNTANTS' REPORT
-------------------------------
To the Board of Directors of Sabine River Holding Corp.:
We have reviewed the accompanying consolidated balance sheet of Sabine River
Holding Corp. and subsidiaries (the "Company") as of September 30, 2001, the
related consolidated statements of operations for the three-month and nine-month
periods ended September 30, 2000 and 2001, and consolidated statements of cash
flows for the nine-month periods then ended. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to such consolidated financial statements for them to be in conformity
with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of the
Company as of December 31, 2000, and the related consolidated statements of
operations, stockholders' equity, and cash flows for the year then ended (not
presented herein); and in our report dated February 13, 2001, we expressed an
unqualified opinion on those consolidated financial statements.
Deloitte & Touche LLP
St. Louis, Missouri
November 7, 2001
1
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in millions, except share data)
December 31, September 30,
2000 2001
------------- --------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 36.4 $ 197.6
Cash and cash equivalents restricted for debt service -- 30.6
Receivable from affiliates 55.0 103.0
Inventories 45.3 60.3
Prepaid expenses 5.0 8.9
------------- --------------
Total current assets 141.7 400.4
PROPERTY, PLANT AND EQUIPMENT, NET 640.8 634.3
OTHER ASSETS 20.2 17.2
------------- --------------
$ 802.7 $ 1,051.9
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 84.7 $ 143.5
Payable to affiliates 30.1 70.8
Accrued expenses and other 22.3 13.5
Current portion of long-term debt - 20.0
Current portion of notes payable to affiliate 2.1 2.6
Accrued taxes other than income 1.4 4.1
------------- --------------
Total current liabilities 140.6 254.5
LONG-TERM DEBT 542.6 522.6
DEFERRED INCOME TAXES 0.4 32.2
NOTE PAYABLE TO AFFILIATE 4.9 4.9
COMMITMENTS AND CONTINGENCIES -- --
COMMON STOCKHOLDERS' EQUITY:
Common stock ($0.01 par value per share;
6,818,182 shares issued and outstanding) 0.1 0.1
Paid-in capital 121.7 121.7
Retained earnings (deficit) (7.6) 115.9
------------- --------------
Total common stockholders' equity 114.2 237.7
------------- --------------
$ 802.7 $ 1,051.9
============= ==============
The accompanying notes are an integral part of these financial statements.
2
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in millions)
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------- -------------------------
2000 2001 2000 2001
----------- ----------- ----------- -----------
NET SALES AND OPERATING REVENUES $ -- $ 461.3 $ -- $ 1,506.0
EXPENSES:
Cost of sales -- 390.3 -- 1,137.6
Operating expenses 1.3 27.3 3.2 114.2
General and administrative expenses 0.3 1.0 0.6 3.0
Depreciation -- 5.3 -- 15.2
----------- ----------- ----------- -----------
1.6 423.9 3.8 1,270.0
OPERATING INCOME (LOSS) (1.6) 37.4 (3.8) 236.0
Interest and finance expense (1.2) (16.6) (2.9) (50.8)
Interest income -- 2.1 0.6 5.0
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES (2.8) 22.9 (6.1) 190.2
Income tax provision -- (8.1) -- (66.7)
----------- ----------- ----------- -----------
NET INCOME (LOSS) $ (2.8) $ 14.8 $ (6.1) $ 123.5
=========== =========== =========== ===========
The accompanying notes are an integral part of these financial statements.
3
SABINE RIVER HOLDING CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in millions)
For the Nine Months
Ended September 30,
-------------------------------
2000 2001
--------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (6.1) $ 123.5
Adjustments
Depreciation -- 15.2
Amortization 1.9 2.3
Deferred taxes -- 31.8
Inventory write-down to market -- 8.7
Other, net -- 0.7
Cash provided by (reinvested in) working capital -
Prepaid expenses (0.9) (3.9)
Inventories -- (23.7)
Affiliate receivable and payable 0.5 (6.8)
Cash and cash equivalents restricted for debt service -- (30.6)
Acounts payable, accrued expenses and taxes other
than income (13.5) 52.7
--------------- ---------------
Net cash provided by (used in) operating activities (18.1) 169.9
--------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (210.6) (8.7)
Cash and cash equivalents restricted for investment in capital additions 44.7 --
--------------- ---------------
Net cash used in investing activities (165.9) (8.7)
--------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 137.6 --
Proceeds from equity contributions 48.7 --
Deferred financing costs (2.3) --
--------------- ---------------
Net cash provided by financing activities 184.0 --
--------------- ---------------
NET INCREASE IN CASH AND CASH EQUIVALENTS -- 161.2
CASH AND CASH EQUIVALENTS, beginning of period 0.1 36.4
--------------- ---------------
CASH AND CASH EQUIVALENTS, end of period $ 0.1 $ 197.6
=============== ===============
The accompanying notes are an integral part of these financial statements.
4
FORM 10-Q - PART I
ITEM 1. FINANCIAL STATEMENTS (continued)
Sabine River Holding Corp. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2001
(tabular dollar amounts in millions of U.S. dollars)
1. Basis of Preparation
Sabine River Holding Corp. is owned 90% by Premcor Inc. and 10% by
Occidental Petroleum Corporation ("Occidental"). Premcor Inc. is owned
principally by Blackstone Capital Partners III Merchant Banking Fund L.P. and
its affiliates ("Blackstone") and Occidental. Sabine River Holding Corp. is the
1% general partner of Port Arthur Coker Company L.P., a limited partnership
("Port Arthur Coker Company"), and the 100% owner of Neches River Holding Corp.
("Neches River Holding"), which is the 99% limited partner of Port Arthur Coker
Company. Port Arthur Coker Company is the 100% owner of Port Arthur Finance
Corp. ("Port Arthur Finance").
The accompanying unaudited consolidated financial statements of Sabine
River Holding Corp. and subsidiaries (the "Company") are presented pursuant to
the rules and regulations of the Securities and Exchange Commission in
accordance with the disclosure requirements for Form 10-Q. In the opinion of the
management of the Company, the unaudited consolidated financial statements
reflected all adjustments (consisting only of normal recurring adjustments)
necessary to fairly state the results for the interim periods presented.
Operating results for the three- and nine-month periods ended September 30, 2001
were not necessarily indicative of the results that may be expected for the year
ended December 31, 2001. These unaudited financial statements should be read in
conjunction with the audited financial statements and notes included in the
Company's 2000 Annual Report on Form 10-K.
2. New Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 1999, the FASB issued
SFAS No. 137 "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB Statement No. 133" which
delayed the effective date of SFAS No. 133 for one year to fiscal years
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138
"Accounting for Certain Derivative Instruments and Hedging Activities" which
amended various provisions of SFAS No. 133. The Company adopted SFAS No. 133,
5
as amended, effective January 1, 2001. The adoption of SFAS No. 133 did not have
a material impact on the financial position or results of operations of the
Company.
On July 20, 2001, the FASB issued SFAS No. 141 "Business Combinations" and
SFAS No. 142 "Goodwill and Other Intangible Assets." SFAS No. 141, which became
effective on issuance, requires business combinations initiated after June 30,
2001 be accounted for using the purchase method of accounting and addresses the
initial recording of intangible assets separate from goodwill. SFAS No. 142
requires that goodwill and intangible assets with indefinite lives will not be
amortized, but will be tested at least annually for impairment. Intangible
assets with finite lives will continue to be amortized. SFAS No. 142 is
effective for fiscal years beginning after December 15, 2001. The Company does
not expect the implementation of these standards to have a material effect on
its financial position and results of operations.
In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset
Retirement Obligations". SFAS No. 143 addresses when a liability should be
recorded for asset retirement obligations and how to measure this liability. The
initial recording of a liability for an asset retirement obligation will require
the recording of a corresponding asset, which will be required to be amortized.
SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The
Company is in the process of evaluating the impact of the adoption of this
standard on its financial position and results of operations.
3. Inventories
The carrying value of inventories consisted of the following:
December 31, September 30,
2000 2001
----------- -----------
Crude oil ........................... $ 44.6 $ 67.8
Blendstocks ......................... 0.7 1.0
Warehouse stock ..................... - 0.2
Inventory write-down to market ...... - (8.7)
--------- --------
$ 45.3 $ 60.3
========= ========
As of September 30, 2001, the Company recorded an $8.7 million inventory
valuation adjustment to write the carrying value of crude oil and blendstock
inventories down to market. This write-down to market was included in "Cost of
sales". The carrying value of crude oil, refined product, and blendstock
inventories approximated market as of December 31, 2000.
4. Property, Plant and Equipment, Net
The Company began depreciating its fixed assets in accordance with Company
policy in January 2001.
5. Other Assets
Other assets consisted of the following:
December 31, September 30,
2000 2001
----------- ----------
Deferred financing costs ........... $ 18.0 $ 15.0
6
Environmental permits ...................... 1.4 1.4
PMI long term crude oil supply agreement ... 0.8 0.8
---------- ---------
$ 20.2 $ 17.2
========== =========
Amortization of deferred financing costs for the three- and nine-month
periods ended September 30, 2001 was $0.8 million (2000 - $0.8 million) and $2.3
million (2000 - $1.9 million), respectively, and was included in "Interest and
finance expense." During 2001, related to the adoption of SFAS No. 133, the
Company wrote-off deferred financing costs associated with an interest rate cap
on its bank senior loan agreement of $0.7 million.
6. Capital Contributions Receivable
In August 1999, Blackstone and Occidental signed capital contribution
agreements totaling $135.0 million for the purpose of funding the construction
of the heavy oil processing facility. Blackstone agreed to contribute $121.5
million and Occidental agreed to contribute $13.5 million. As of September 30,
2001, Blackstone had contributed $109.6 million and Occidental had contributed
$12.2 million. The obligation to fund the capital contributions was contingent
upon the Company borrowing funds under the bank senior loan agreement. In the
third quarter, the Company decided not to borrow the remaining loan commitment
under the bank senior loan agreement, and consequently, forfeited the remaining
capital contributions. Accordingly, as of September 30, 2001, the remaining
unfunded capital contributions of $13.2 million were no longer recorded as a
capital contribution receivable. The ability to draw any remaining funds under
the bank senior loan agreement and receive the remaining capital contributions
expired in September of 2001 upon the achievement of substantial reliability of
the heavy oil upgrade facility, as defined for purposes of the financing
documents.
7. Interest and Finance Expense
Interest and finance expense consisted of the following:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
--------------------- ---------------------
2000 2001 2000 2001
------- ------- -------- -------
Interest expense ...... $ 14.7 $ 14.8 $ 39.9 $ 46.5
Financing costs ....... 1.2 1.9 2.9 5.2
Capitalized interest .. (14.7) (0.1) (39.9) (0.9)
------- ------- -------- -------
$ 1.2 $ 16.6 $ 2.9 $ 50.8
======= ======= ======== =======
Cash paid for interest for the three-and nine-month periods ended
September 30, 2001 was $23.1 million (2000 - $ 21.4 million) and $55.3 million
(2000 - $ 42.1 million), respectively.
8. Income Taxes
The Company made net cash income tax payments during the three-month and
nine-month periods ended September 30, 2001 of $13.0 million (2000 - none) and
$13.0 million (2000 - none), respectively.
9. Port Arthur Coker Company Condensed Consolidated Financial Information
7
Sabine River Holding Corp directly owns a 1% general partnership interest
in Port Arthur Coker Company and through its wholly-owned subsidiary, Neches
River Holding, owns the remaining 99% limited partnership interest. Port Arthur
Finance, which is wholly owned by Port Arthur Coker Company, issued debt on Port
Arthur Coker Company's behalf. Both the Company and Neches River Holding fully
and unconditionally guarantee the debt issued by Port Arthur Finance. Port
Arthur Coker Company is the only company with operations in the consolidated
financial statements of the Company. Neither Neches River Holding nor Port
Arthur Finance have independent operations.
Port Arthur Coker Company's condensed consolidated financial information
consisted of the following:
Consolidated statement of operations:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------ ------------------------
2000 2001 2000 2001
----------- ---------- ----------- ----------
Revenues................................ $ -- $ 461.3 $ -- $ 1,506.0
Cost of sales........................... -- 390.3 -- 1,137.6
Operating expenses...................... 1.3 27.3 3.2 114.2
General and administrative expenses..... 0.3 0.9 0.6 2.9
Depreciation............................ -- 5.3 -- 15.2
----------- ---------- ----------- ----------
(1.6) 37.5 (3.8) 236.1
Interest expense and finance income, net 1.2 14.5 2.3 45.8
----------- ---------- ----------- ----------
Net income (loss) ...................... $ (2.8) $ 23.0 $ (6.1) $ 190.3
=========== ========== =========== ==========
Consolidated balance sheet information:
December 31, September 30
2000 2001
----------- -----------
Total current assets..................................... $ 137.1 $ 383.2
Property, plant and equipment ........................... 640.8 634.3
Total assets ............................................ 798.1 1,034.7
Total current liabilities ............................... 140.5 219.8
Long term debt .......................................... 542.6 522.6
Partners' capital contributed ........................... 121.8 108.8
Retained earnings (deficit) ............................. (11.7) 287.4
Total liabilities and partners' capital ................. 798.1 1,034.7
In the third quarter, Port Arthur Coker Company distributed cash of $12.9
million to Sabine River Holding Corp. and $0.1 million to Neches River Holding.
10. Related Party Transactions
Port Arthur Coker Company and The Premcor Refining Group Inc.
Port Arthur Coker Company and The Premcor Refining Group Inc. (the "Premcor
Refining Group") have entered into certain agreements associated with the
ongoing operations of the coker, hydrocracking, and sulfur removal facilities of
the Port Arthur Coker Company and the Premcor Refining Group's Port
8
Arthur refinery. Port Arthur Coker Company's general partner Sabine River
Holding Corp. and the parent company of the Premcor Refining Group, Premcor USA
Inc., are subsidiaries of Premcor Inc. Related party receivables, payables,
revenues, cost of sales, and operating expenses from these agreements were as
follows:
As of September 30, 2001, Port Arthur Coker Company had an outstanding
receivable from the Premcor Refining Group of $85.7 million (December 31, 2000 -
$50.4 million) and a payable to the Premcor Refining Group of $36.3 million
(December 31, 2000 - $28.0 million) related to ongoing operations. As of
September 30, 2001, Port Arthur Coker Company had a note payable to the Premcor
Refining Group of $7.5 million (December 31, 2000 - $7.0 million) related to
construction management services of which $4.9 million (December 31, 2000 - $4.9
million) was accounted for as a long-term liability and the remainder as a
current liability.
Port Arthur Coker Company generated $466.2 million and $1,500.9 million in
revenues for the three-and nine-month periods ended September 30, 2001,
respectively, primarily from the sales of finished and intermediate refined
products and crude oil to the Premcor Refining Group. Port Arthur Coker Company
incurred $23.9 million and $80.7 million in costs of sales for the three-month
and nine-month periods ended September 30, 2001, respectively. These costs were
associated with the purchases of feedstocks and hydrogen and the incurrence of
pipeline tariffs from the Premcor Refining Group for the three-and nine-month
periods ended September 30, 2001. Port Arthur Coker Company recorded operating
expenses of $10.4 million and $43.8 million respectively, for the three-and
nine-month periods ended September 30, 2001. These operating expenses related to
services provided by the Premcor Refining Group and lease operating expenses
under the various agreements between the Premcor Refining Group and Port Arthur
Coker Company.
11. Commitments and Contingencies
In July 1999, Port Arthur Coker Company entered into a contract with Foster
Wheeler USA for the engineering, procurement and construction of the heavy oil
processing facility. Under this construction contract, Foster Wheeler USA
engineered, designed, procured equipment for, constructed, tested, and oversaw
start-up of the heavy oil processing facility and its integration with the Port
Arthur refinery of the Premcor Refining Group. Under the construction contract,
Port Arthur Coker Company paid Foster Wheeler USA a fixed price of approximately
$544 million. The contract has provisions whereby Foster Wheeler USA will pay
Port Arthur Coker Company up to $145 million in damages for delays in achieving
mechanical completion or guaranteed reliability, based on a defined formula. As
of September 30, 2001 the heavy oil processing facility had reached mechanical
completion and guaranteed reliability.
Tier 2 Motor Vehicle Emission Standards. In February 2000, the
Environmental Protection Agency ("EPA") promulgated the Tier 2 Motor Vehicle
Emission Standards Final Rule for all passenger vehicles, establishing standards
for sulfur content in gasoline. These regulations mandate that the sulfur
content of gasoline at any refinery not exceed 30 ppm during any calendar year
by January 1, 2006. These requirements will be phased in beginning on January 1,
2004. Modifications will be required to the Company's facility as a result of
the Tier 2 standards. Based on preliminary estimates, the Company believes that
compliance with the new Tier 2 gasoline specifications will require capital
expenditures in the aggregate through 2005 in a range of $20 million to $25
million. More than 90% of the projected investment is expected to be incurred
during 2002 through 2004 with the greatest concentration of spending occurring
in 2003.
Low Sulfur Diesel Standards. In addition, in January 2001, the EPA
promulgated its on-road diesel regulations, which will require a 97% reduction
in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with
full compliance by January 1, 2010. Refining industry groups have filed two
lawsuits, which may delay implementation of the on-road diesel rule beyond 2006.
In its release, the EPA
9
estimated that the overall cost to fuel producers of the reduction in sulfur
content would be approximately $0.04 per gallon. The EPA has also announced its
intention to review the sulfur content in diesel fuel sold to off-road
consumers. If regulations are promulgated to regulate the sulfur content of
off-road diesel, the Company expects the sulfur requirement to be either 500
ppm, which is the current on-road limit, or 15 ppm, which will be the future
on-road limit. If the new off-road standard is 500 ppm, the Company will not
need to incur any capital expenditures to comply with the diesel standards
because the Port Arthur refinery currently meets the 500 ppm specification. The
Company would thus continue to have a market for its current diesel production
at Port Arthur, albeit a smaller and lower priced market, and therefore could
elect not to make any capital expenditures necessary to comply with the new
on-road standard. Depending upon the standard promulgated for off-road diesel,
if any, and the compliance strategy the Company adopts, the Company estimates
that its capital expenditure cost in the aggregate through 2006 of complying
with the diesel standards utilizing existing technologies may range from zero to
$175 million. Approximately 90% of the projected investment, if necessary, is
expected to be incurred during 2004 through 2006 with the greatest concentration
of spending occurring in 2005. The decision of which strategy to pursue will be
made in conjunction with the Premcor Refining Group.
10
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Forward-Looking Statements
Certain statements in this document are forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. These statements are subject to the safe harbor
provisions of this legislation. Words such as "expects," "intends," "plans,"
"projects," "believes," "estimates," "will" and similar expressions typically
identify such forward-looking statements.
Even though we believe our expectations regarding future events are based
on reasonable assumptions, forward-looking statements are not guarantees of
future performance. Important factors that could cause actual results to differ
materially from those contained in our forward-looking statements include, among
others, changes in:
. Industry-wide refining margins;
. Crude oil and other raw material costs, embargoes, industry expenditures
for the discovery and production of crude oil, and military conflicts
between, or internal instability in, one or more oil-producing countries,
and governmental actions;
. Market volatility due to world and regional events;
. Availability and cost of debt and equity financing;
. Labor relations;
. U.S. and world economic conditions;
. Supply and demand for refined petroleum products;
. Reliability and efficiency of our operating facilities which are effected
by such potential hazards as equipment malfunctions, plant
construction/repair delays, explosions, fires, oil spills and the impact of
severe weather;
. Actions taken by competitors which may include both pricing and expansion
or retirement of refinery capacity;
. The enforceability of contracts;
. Civil, criminal, regulatory or administrative actions, claims or
proceedings and regulations dealing with protection of the environment;
. Other unpredictable or unknown factors not discussed.
Because of all of these uncertainties, and others, you should not place
undue reliance on our forward-looking statements.
11
Overview
We were formed to develop, construct, own, operate, and finance a heavy oil
processing facility that includes a new 80,000 barrel per stream day delayed
coking unit, a 35,000 barrel per stream day hydrocracker unit, and a 417 long
tons per day sulfur complex that are operated in conjunction with the refining
assets at the Port Arthur, Texas refinery of an affiliate, The Premcor Refining
Group Inc. This heavy oil processing facility along with modifications made by
Premcor Refining Group at their Port Arthur refinery allows the refinery to
process primarily lower-cost, heavy sour crude oil. We were incorporated in May
of 1999 and were capitalized in August of 1999. We are the 1% general partner of
Port Arthur Coker Company L.P. and the 100% owner of Neches River Holding Corp.,
which is the 99% limited partner of Port Arthur Coker Company. We are owned 90%
by Premcor Inc. and 10% by Occidental Petroleum Corporation.
In January 2001, we began full operation of our newly constructed coking,
hydrocracking, and sulfur removal units. Premcor Refining Group began
construction of these new units in 1998. In the third quarter of 1999, we
purchased a portion of the work in progress and certain other related assets
from Premcor Refining Group. We financed and completed the construction of the
heavy oil processing facility. Start-up of our units occurred in stages, with
the sulfur removal units and the coker unit beginning operations in December
2000 and the hydrocracker unit beginning operations in January 2001. Substantial
reliability, as defined in our financing documents, of the heavy oil processing
facility was achieved as of September 30, 2001. Additional information regarding
the construction of the heavy oil processing facility is included in our Annual
Report on Form 10-K for the year ended December 31, 2000.
We entered into agreements with Premcor Refining Group associated with the
operations of our heavy oil processing facility and Premcor Refining Group's
Port Arthur refinery, including supply and services, product purchase, and
ancillary unit lease agreements as described below:
. We lease 100% of Premcor Refining Group's crude, vacuum and other
ancillary units for a quarterly lease fee, which is reported as an
operating expense. Premcor Refining Group utilizes through the
processing arrangement discussed below approximately 20%, or 50,000
barrels per day ("bpd") of crude distillation capacity and this is
recorded as revenue. As a result of this arrangement, we are utilizing
approximately 80%, or 200,000 bpd, of the Port Arthur refinery's crude
distillation capacity.
. Our production consists of intermediate refined products and lesser
volumes of finished light products, petroleum coke and sulfur, all of
which are sold at fair market value to Premcor Refining Group for
either further processing into higher value finished refined products
or immediate sale to third parties.
. Premcor Refining Group utilizes a portion of the capacity of our heavy
oil processing facility for a monthly processing fee. This fee is
recorded as an offset to operating expenses.
. We pay Premcor Refining Group a fee for providing certain services and
supplies, including employee, maintenance and energy costs. These fees
are included in operating expenses. We also pay Premcor Refining Group
for pipeline access and the use of their Port Arthur refinery dock.
These fees are included in cost of sales.
Factors Affecting Operating Results
12
Our earnings and cash flow from operations are primarily affected by the
relationship between intermediate and refined product prices and the prices for
crude oil. The cost to acquire feedstocks and the price for which intermediate
and refined products are ultimately sold depends on numerous factors beyond our
control, including the supply of, and demand for, crude oil, gasoline and other
refined products which, in turn, depend on, among other factors, changes in
domestic and foreign economies, weather conditions, domestic and foreign
political affairs, production levels, the availability of imports, the marketing
of competitive fuels and the extent of government regulation. While our net
sales and operating revenues fluctuate significantly with movements in industry
crude oil prices, such prices do not generally have a direct long-term
relationship to net earnings. Crude oil price movements may impact net earnings
in the short term because of fixed price crude oil purchase commitments. The
effect of changes in crude oil prices on our operating results is influenced by
the rate at which the prices of refined products adjust to reflect such changes.
Feedstock, intermediate and refined product prices are also affected by
other factors, such as product pipeline capacity, local market conditions and
the operating levels of competing refineries. Crude oil costs and the price of
intermediate and refined products have historically been subject to wide
fluctuations. Expansion of existing facilities and installation of additional
refinery crude distillation and upgrading facilities, price volatility,
international political and economic developments and other factors beyond our
control are likely to continue to play an important role in refining industry
economics. These factors can impact, among other things, the level of
inventories in the market resulting in price volatility and a reduction in
product margins. Moreover, the industry typically experiences seasonal
fluctuations in demand for refined products, such as an increased demand for
gasoline during the summer driving season and for home heating oil during the
winter, primarily in the Northeast.
In order to assess our operating performance, we compare our gross margin
against an industry gross margin benchmark. The industry gross margin is
calculated by assuming that three barrels of benchmark light sweet crude oil is
converted, or cracked, into two barrels of conventional gasoline and one barrel
of high sulfur diesel fuel. This is referred to as the 3/2/1 crack spread. Since
we calculate the benchmark margin using the market value of U.S. Gulf Coast
gasoline and diesel fuel against the market value of West Texas Intermediate
crude oil, we refer to the benchmark as the Gulf Coast 3/2/1 crack spread, or
simply, the Gulf Coast crack spread. The Gulf Coast crack spread is expressed in
dollars per barrel and is a proxy for the per barrel margin that a sweet crude
oil refinery situated on the Gulf Coast would earn assuming it produced and sold
the benchmark production of conventional gasoline and high sulfur diesel fuel.
The Port Arthur refinery configuration is unique and has logistical advantages
to a benchmark refinery, and as a result, our gross margin per barrel of
throughput will differ from the benchmark crack spread.
Of our total feedstocks, we are able to process up to 80% heavy sour crude
oil that has historically cost less than West Texas Intermediate crude oil. We
measure the cost advantage of heavy crude oil by calculating the spread between
the value of Maya crude oil produced in Mexico to the value of West Texas
Intermediate crude oil because Maya is our predominant heavy sour crude oil. The
cost advantage of sour crude oil is measured by calculating the spread between
the value of West Texas Sour crude oil to the value of West Texas Intermediate
crude oil.
The sales value of our production is also an important consideration in
understanding our results. Our product slate is substantially comprised of
intermediate refined products that are sold to Premcor Refining Group for
further processing. Since intermediate refined products carry a value less than
finished refined products, our typical product slate carries a sales value lower
than that for the products used to calculate the Gulf Coast crack spread.
13
Our operating cost structure is also important to our profitability. Major
operating costs include energy, employee labor, lease fees, maintenance,
including contract labor, and environmental compliance. By far, the predominant
variable cost is energy and the most important benchmark for energy costs is the
value of natural gas.
Consistent, safe and reliable operations at our heavy oil processing
facility and at the Port Arthur refinery in general is a key to our financial
performance. Unplanned downtime of refinery assets generally results in lost
margin opportunity, increased maintenance expense and a temporary increase in
working capital investment and related inventory position. The financial impact
of planned downtime, such as major turnaround maintenance, is mitigated through
a diligent planning process that considers such things as margin environment,
availability of resources to perform the needed maintenance and feedstock
logistics.
The nature of our business leads us to maintain a substantial investment in
petroleum inventories. As petroleum feedstocks and intermediate products are
essentially commodities, we have no control over the changing market value of
our investment. Because most of our titled inventory is valued under the
first-in, first-out costing method, price fluctuations on our titled inventory
can have material effects on our financial results. Our petroleum inventories
consist principally of crude oil since we sell all of our production to Premcor
Refining Group under the product purchase agreement.
We have a long-term crude oil supply agreement with PMI Comercio
International S.A. de C.V. that provides us with a stable and secure supply of
Maya crude oil. An important feature of this agreement is a mechanism intended
to provide us with a minimum average coker gross margin and moderate
fluctuations in our coker gross margins during the eight-year period from April
1, 2001. This mechanism uses a formula to approximate quarterly coker gross
margins and provides for discounts or premiums on our crude oil purchases from
PMI in subsequent quarters based on the following methodology.
Quarterly formula coker gross margins that exceed the minimum average coker
gross margin of $15 per barrel result in a quarterly surplus, while quarterly
formula coker gross margins that fall short of the minimum average coker gross
margin of $15 per barrel result in a quarterly shortfall. The contract provides:
. In the case of a quarterly shortfall amount, the amount of such
shortfall, less the amount, if any, by which cumulative surpluses
exceed cumulative shortfalls for prior quarters, will be taken as a
discount on our crude oil purchases from PMI in the succeeding
quarter; provided, however, that in any given quarter the discount we
receive may not exceed $30 million regardless of the magnitude of the
net shortfalls accumulated. Any such "excess discount" will be carried
forward and applied in subsequent quarters; and
. In the case of a quarterly surplus amount, the lesser of the
amounts of such surplus and the amount, if any, by which cumulative
shortfalls exceed cumulative surpluses for prior quarters, will be
paid as a premium on our crude oil purchases from PMI in the
succeeding quarter; provided, however, that in any given quarter the
premium we pay may not exceed $20 million. Any such "excess premium"
will be carried forward and applied in subsequent quarters.
As of September 30, 2001, as a result of the favorable market conditions
related to the value of Maya crude oil versus the refined products derived from
it, the amount of cumulative quarterly surpluses exceeded cumulative quarterly
shortfalls by $112.5 million. As a result, to the extent we experience quarterly
shortfalls in formula coker gross margins going forward, the price we pay for
Maya crude oil in succeeding quarters will not be discounted unless cumulative
surpluses are offset by cumulative shortfalls. Also, because the amount of any
premium we pay on the price of Maya crude oil is limited to the amount of net
cumulative shortfalls in prior quarters, we will not be required to pay a
premium in succeeding quarters in excess of the net cumulative shortfall. In
other words, we retain the benefit of net cumulative surpluses in our formula
coker gross margins in excess of the support amount of $15 per barrel.
Industry Outlook
Our earnings depend largely on refining industry margins, which have been
and continue to be volatile. The cost of crude oil and intermediate feedstocks
we purchase and the prices of refined products we sell have fluctuated widely in
the past. Crude oil, intermediate feedstocks and refined product prices depend
on numerous factors beyond our control. While it is impossible to predict
refining margins due to the uncertainties associated with global crude oil
supply and domestic demand for refined products, we believe that refining
margins for United States refineries will generally remain above those
experienced in the period 1995 through 2000 as growth in demand for refining
products in the United States, particularly transportation fuels, continues to
exceed the ability of domestic refiners to increase capacity. The review of 2001
year-to-date refining industry margins summarized below gives some indication of
the volatility that exists in the industry.
Over the first five months of 2001, the market price of distillate relative
to crude oil was above average due to low industry inventories and strong
consumer demand brought about by the relatively cold winter weather in the
northeast United States and eastern Canada and high natural gas prices which led
to an increase in industrial users switching from natural gas to fuel oil. In
addition, gasoline margins were above average, primarily because substantial
scheduled and unscheduled refinery maintenance turnaround activity in the United
States in late 2000 and early 2001 resulted in inventories that did not
14
increase in a manner typically experienced during the winter. The increased
demand for refined products due to the relatively cold winter and the decreased
supply due to high turnaround activity, led to increasing refining margins
during the first five months of 2001. As a result, the average margin achieved
over the first half of 2001 was approximately twice the average for the first
six month period over the last four years.
During the ensuing four months of 2001 the refining markets were extremely
volatile. During June and July 2001, refining margins declined from the highs
experienced earlier in the year. This decline was largely the result of
increasing product inventories due to high refinery production rates, excessive
product import levels and slowing consumer demand. The healthy refining margins
realized in early 2001 led refiners to postpone scheduled turnarounds in order
to maximize utilization rates. Import levels increased because of high domestic
product prices relative to foreign product prices. Growth in consumer demand
slowed as a result of high prices and a weakening economy. However, refining
margins strengthened in August due to other refiners' unplanned downtime and
decisions to undertake delayed maintenance turnarounds and due to lower product
imports. The terrorist attacks on September 11th created a downward spiral of
refining margins, lowering demand for distillates, in particular jet fuel, and
gasoline. The lower demand has led to higher gasoline and distillate
inventories.
Average discounts for sour and heavy sour crude oil increased in the first
nine months of 2001 from already favorable 2000 levels due to increasing
worldwide production of sour and heavy sour crude oil relative to production of
light sweet crude oil, coupled with continuing demand for light sweet crude oil.
In April 2001, the discount for heavy sour crude oil versus West Texas
Intermediate widened to more than double historical averages. Although the heavy
sour crude oil discount to West Texas Intermediate crude oil has narrowed from
these record highs, the discount continues to exceed historic levels. Sweet
crude oil continues to trade at a premium to West Texas Sour due to continued
high demand for sweet crude oil resulting from the more stringent fuel
specifications implemented in the United States and Europe and the higher
margins for light products.
In the near term, we anticipate that refining margins will remain at
slightly depressed levels as the country and the world wait to see what will
happen in the war against terrorism both here in the United States and in the
Middle East. The attacks and the subsequent retaliation have raised questions
about gasoline and distillate demand and crude oil supply, particularly the
supply from the Middle East. Additionally, the depth of economic recession in
the United States, and the decline in consumer spending confidence and the weak
industrial sector will curtail demand for petroleum products.
In the long-term, we expect refined product supply and demand balances to
tighten worldwide as growth in demand for refined products is expected to exceed
net capacity growth, particularly for transportation fuels. A portion of the
supply growth due to new capacity built by foreign refiners and the continued
de-bottlenecking and expansion of existing refineries will likely be offset by
more stringent environmental specifications and refinery closures resulting from
capital requirements to meet worldwide low-sulfur gasoline and diesel
specifications. We expect that the worldwide growth in production of sour and
heavy sour crude oil will continue to exceed increases in the production of
light sweet crude oil and that this, when coupled with the continuing demand for
light sweet crude oil, will support a wide spread between the prices of light
sweet and heavy sour crude oil. In summary, we believe refining margins in the
United States will benefit from continuing favorable supply and demand
fundamentals.
15
Results of Operations
The following table reflects our financial and operating highlights for the
three- and nine-month periods ended September 30, 2000 and 2001.
Financial Results For the Three Months Ended For the Nine Months Ended
(in millions, except as noted) September 30, September 30,
--------------------------------- -------------------------------
2000 2001 2000 2001
---------------- --------------- --------------- --------------
Net sales and operating revenues $ -- $ 461.3 $ -- $ 1,506.0
Cost of sales -- 390.3 -- 1,137.6
---------------- --------------- --------------- --------------
Gross Margin -- 71.0 -- 368.4
Operating expenses 1.3 27.3 3.2 114.2
General and administrative expenses 0.3 1.0 0.6 3.0
---------------- --------------- --------------- --------------
EBITDA /(1)/ (1.6) 42.7 (3.8) 251.2
Depreciation expense -- 5.3 -- 15.2
---------------- --------------- --------------- --------------
Operating income (loss) (1.6) 37.4 (3.8) 236.0
Interest expense and finance income, net (1.2) (14.5) (2.3) (45.8)
Income tax provision -- (8.1) -- (66.7)
---------------- --------------- --------------- --------------
Net income (loss) available to common
stockholders $ (2.8) $ 14.8 $ (6.1) $ 123.5
================ =============== =============== ==============
(1) Earnings before interest, income taxes, depreciation, and amortization
Market Indicators For the Three Months For the Nine Months
(dollars per barrel, except as noted) Ended September 30, Ended September 30,
------------------- -------------------
2000 2001 2000 2001
---- ---- ---- ----
West Texas Intermediate, (WTI) crude oil .... $ 31.75 $ 26.81 $ 29.85 $ 27.84
Gulf Coast Crack Spread (3/2/1) ............. $ 4.37 $ 3.41 $ 4.32 $ 4.98
Crude Oil Differentials:
WTI less WTS (sour) .................... $ 1.94 $ 2.02 $ 1.97 $ 3.11
WTI less Maya (heavy sour) ............. $ 7.39 $ 7.63 $ 6.49 $ 9.57
WTI less Dated Brent (foreign) ......... $ 1.19 $ 1.43 $ 1.76 $ 1.68
Natural gas (per mmbtu) ..................... $ 4.55 $ 3.01 $ 3.50 $ 4.90
Selected Volumetric and Per Barrel Data For the Three Months For the Nine Months
(in thousands of barrels per day, except as noted) Ended September 30, Ended September 30,
--------------------------------- -------------------------------
2000 2001 2000 2001
---- ---- ---- ----
Production .................................. -- 175.1 -- 191.3
Crude oil throughput ........................ -- 177.1 -- 180.2
Per barrel of throughput (in dollars):
Gross margin .............................. -- $ 4.36 -- $ 7.49
Operating expenses ........................ -- $ 1.68 -- $ 2.32
16
Three months ended Three months ended
September 30, 2000 September 30, 2001
------------------------------- -----------------------------
Selected Volumetric Data
(in thousands of barrels per day) Barrels Percent Barrels Percent
---------------- ------------- ------------- --------------
Feedstocks:
Crude oil throughput:
Light/medium sour -- -- 36.3 20%
Heavy sour -- -- 140.8 80%
---------------- ------------- ------------- --------------
Total crude oil -- -- 177.1 100%
================ ============= ============= ==============
Production:
Intermediate throughput produced for Premcor
Refining Group -- -- 157.8 90%
Petroleum coke and sulfur -- -- 17.3 10%
---------------- ------------- ------------- --------------
Total production -- -- 175.1 100%
================ ============= ============= ==============
Nine months ended September Nine months ended September
30, 2000 30, 2001
------------------------------- -----------------------------
Selected Volumetric data
(in thousands of barrels per day) Barrels Percent Barrels Percent
---------------- ------------- ------------- --------------
Feedstocks:
Crude oil throughput:
Light/medium sour -- -- 37.1 21%
Heavy sour -- -- 143.1 79%
---------------- ------------- ------------- --------------
Total crude oil -- -- 180.2 100%
================ ============= ============= ==============
Production:
Intermediate throughput produced for Premcor
Refining Group -- -- 174.3 91%
Petroleum coke and sulfur -- -- 17.0 9%
---------------- ------------- ------------- --------------
Total production -- -- 191.3 100%
================ ============= ============= ==============
17
Overview. Net income increased $17.6 million to $14.8 million in the third
quarter of 2001 from a net loss of $2.8 million in the corresponding period in
2000. Operating income increased $39.0 million to $37.4 million in the third
quarter of 2001 from a loss of $1.6 million in the corresponding period in 2000.
Net income increased $129.6 million to $123.5 million in the first nine months
of 2001 from a net loss of $6.1 million in the corresponding period in 2000.
Operating income increased $239.8 million to $236.0 million in the first nine
months of 2001 from a loss of $3.8 million in the corresponding period in 2000.
The operating results for 2001 compared to 2000 were affected by the completion
and operation of the heavy oil upgrade project. See "Factors Affecting Operating
Results" for a detailed discussion of how the completion of the heavy oil
upgrade project has affected our results.
Net Sales and Operating Revenue. Net sales and operating revenues were
$461.3 million and $1,506.0 million in the third quarter and first nine months
of 2001, respectively.
Gross Margin. Gross margin was $71.0 million and $368.4 million in the
third quarter and first nine months of 2001, respectively. The gross margin for
the third quarter reflected lower Gulf Coast crack spreads, narrowing heavy sour
crude oil differentials, and operational issues related to a lightning strike to
the crude unit in May of 2001. The first nine months of 2001 reflected strong
market conditions in the first half of the year partially offset by operational
issues and slowing market conditions in the third quarter. For the first nine
months of 2001, our gross margin benefited from the strong crude oil discounts
reflected in the significant differentials between WTI and sour and heavy sour
crude oil and improvements to refining margins as reflected in the Gulf Coast
crack spread.
Crude oil throughput rates averaged 177,100 bpd and 180,200 bpd, of the
available 200,000 bpd, in the third quarter and first nine months of 2001,
respectively. Crude oil throughput rates in the third quarter of 2001 were
restricted due to a lightning strike in early May and a ten day shutdown of the
crude unit in July to repair the damage caused by the lightning strike. Both the
crude unit rate restriction and subsequent downtime for repairs lowered
feedstock throughput rates by approximately 22,000 bpd during the third quarter.
Crude oil throughput rates in the first nine months of 2001 were restricted due
to the lightning strike plus restrictions on the crude unit as units downstream
were in start-up operations during the first quarter. The crude unit throughput
rates were close to capacity during the months of August and September of 2001.
The 80,000 bpd coker unit averaged approximately 70,300 bpd and 73,900 bpd
of throughput during the third quarter and first nine months of 2001,
respectively. Overall throughput rates were lower than capacity due to the
restrictions from the lightning strike, a planned maintenance turnaround of the
Premcor Refining Group's alkylation unit and the fine tuning of operations
associated with the start-up of our coker and hydrocracker units.
Operating Expenses. Operating expenses increased $26.0 million to $27.3
million in the third quarter of 2001 from $1.3 million in the corresponding
period in 2000. Operating expenses increased $111.0 million to $114.2 million in
the first nine months of 2001 from $3.2 million in the corresponding period in
2000. Operating expenses included employee, catalyst/chemical, repair and
maintenance, insurance, taxes, and energy costs as well as costs, net of lease
fees, related to the service and supply agreements with Premcor Refining Group.
In the first nine months of 2001 our operating expenses were negatively impacted
by the significant rise in energy costs, particularly in the first six months of
the year, as reflected in the natural gas prices.
18
General and Administrative Expenses. General and administrative expenses
increased $0.7 million to $1.0 million in the third quarter of 2001 from $0.3
million in the corresponding period in 2000. General and administrative expenses
increased $2.4 million to $3.0 million in the first nine months of 2001 from
$0.6 million in the corresponding period in 2000. The 2001 general and
administrative expenses primarily included costs associated with the services
and supply agreement with Premcor Refining Group. This agreement did not take
affect until the fourth quarter of 2000. The 2000 general and administrative
expenses primarily included employee and professional fee expenses related to
the pre-operation period.
Depreciation and Amortization. Depreciation and amortization was $5.3
million and $15.2 million in the third quarter and first nine months of 2001,
respectively. We began depreciating our assets in accordance with our property,
plant and equipment policy during the first quarter of 2001, following the
substantial completion of the heavy oil upgrade project in stages, beginning
December 2000 and commencement of operations.
Interest Expense and Finance Income, net. Interest expense and finance
income, net increased $13.3 million to $14.5 million in the third quarter of
2001 from $1.2 million in the corresponding period in 2000. Interest expense and
finance income, net increased $43.5 million to $45.8 million in the first nine
months of 2001 from $2.3 million in the corresponding period in 2000. In 2000,
the majority of the interest costs were capitalized as part of the heavy oil
upgrade project. These costs are being expensed in 2001 upon the completion of
the project.
Income Tax Provision. An income tax provision of $8.1 million in the third
quarter of 2001 and an income tax provision of $66.7 million in the first nine
months of 2001 represented an approximate 35% effective tax rate on pretax
income or loss. In September 2001, under the terms of our tax sharing agreement
with the common parent of our consolidated group, Premcor Inc., and the common
security agreement related to our senior debt, we made a federal estimated
income tax payment of $13.0 million.
Liquidity and Capital Resources
Cash flows from Operating Activities
Cash flows provided by operating activities for the nine-month period ended
September 30, 2001 was $200.5 million compared to cash used in operating
activities of $18.1 million for the same period last year. These cash flows
mainly resulted from the earnings from operations in 2001 and the loss during
the development stage in 2000. Working capital changes were principally due to
the shift from accounts payables related solely to capital expenditure accruals
to accounts receivable, accounts payable and inventory related to full
operations.
As of September 30, 2001, we had a cash balance of $228.2 million. Under a
common security agreement related to our senior debt, this cash is reserved for
specific operational uses and mandatory debt repayment. The operational uses
include various levels of spending, such as current and operational working
capital needs, interest and principal payments, taxes, and maintenance and
repairs. Cash is applied to each level until that level has been fully funded,
upon which the remaining cash flows to the next level. Once these spending
levels are funded, any cash surplus satisfies obligations of a debt service
reserve and mandatory debt repayment with funding occurring semiannually on
January and July 15th. The cash balance of $228.2 million included $30.6 million
restricted for debt service payments on our long-term debt.
In order to provide security to PMI Comercio Internacional, S.A. de C.V.
for our obligation to pay for shipments of Maya crude oil under a long term
crude oil supply agreement, we obtained from Winterthur International Insurance
Company Limited an oil payment guaranty insurance policy for the
19
benefit of PMI. This oil payment guaranty insurance policy is in the amount of
$150 million and will be a source of payment to PMI if we fail to pay PMI for
one or more shipments of Maya crude oil. Under certain senior debt documents, we
are required to reimburse Winterthur for any payments they make on this policy.
This reimbursement obligation to Winterthur has a priority claim on all of the
collateral held for the senior debt equal to the note holders and holders of
Port Arthur Coker Company's other senior debt, except in specified circumstances
in which it has a senior claim to these parties. As of September 30, 2001,
$123.9 million of crude oil purchase commitments were outstanding related to
this policy.
We also have in place a $35 million working capital facility which is
primarily for the issuance of letters of credit for the purchases of non-Maya
crude oil. As of September 30, 2001, $18.3 million of the facility was utilized
for letters of credit.
Cash Flows from Investing Activities
Cash flows used in investing activities were $8.7 million for the
nine-month period ended September 30, 2001 as compared to $165.9 million in the
same period last year. Expenditures for property, plant and equipment in 2000
and 2001 were associated with the construction of the heavy oil upgrade
facility. All proceeds from our 1999 debt financings were restricted for use on
the construction, financing, and start-up operations of the heavy oil upgrade
facility. As a result, cash and cash equivalents associated with the
construction of the heavy oil upgrade facility were classified as a non-current
asset and the restricted cash and cash equivalent activity was reflected as
investing activity in 2000.
We classify our capital expenditures into two categories, mandatory and
discretionary. Mandatory capital expenditures, such as for turnarounds and
maintenance, are required to maintain safe and reliable operations or to comply
with regulations pertaining to soil, water and air contamination or pollution
and occupational, safety and health issues. We estimate that total mandatory
capital and turnaround expenditures will average approximately $10 million per
year over the next four years. This estimate includes the capital costs
necessary to comply with environmental regulations, except for Tier 2 gasoline
standards and on-road diesel regulations described below. Because our assets
have been in operation for such a short period of time, we have not incurred any
mandatory capital and refinery maintenance turnaround expenditures in 2001.
Discretionary capital expenditures are undertaken by us on a voluntary basis
after thorough analytical review and screening of projects based on the expected
return on incremental capital employed. Discretionary capital projects generally
involve an expansion of existing capacity, improvement in product yields and/or
a reduction in operating costs. We plan to fund both mandatory and discretionary
capital expenditures with cash flow from operations. Accordingly, total
discretionary capital expenditures may be less than budget if cash flow is lower
than expected and higher than budget if cash flow is better than expected. Our
discretionary capital expenditure budget related to the completion of the heavy
oil processing facility is approximately $15.3 million in 2001, of which $8.7
million has been spent as of September 30, 2001. We currently plan to spend
approximately $10 million on discretionary capital projects in 2002.
In addition to mandatory capital expenditures, we expect to incur
significant costs in order to comply with environmental regulations discussed
below. For example, the Environmental Protection Agency has promulgated new
regulations under the Clean Air Act that establish stringent sulfur content
specifications for gasoline and on-road diesel fuel designed to reduce air
emissions from the use of these products. The gasoline specifications, referred
to as the Tier 2 standards, have been enacted and will be phased in beginning in
2004, with full compliance required by January 1, 2006. Based on our preliminary
estimates, we believe that compliance with the Tier 2 gasoline standards will
require us to spend between $20 million and $25 million in the aggregate through
2005. More than 90% of the projected investment is expected to be incurred
during 2002 through 2004 with the greatest concentration of spending occurring
in 2003. The low sulfur highway on-road diesel regulations will require a 97%
reduction in the sulfur content of diesel fuel sold for highway use by June 1,
2006, with full compliance by January 1, 2010. The Environmental Protection
Agency has also announced its intention to review the sulfur content in diesel
fuel sold to off-road consumers. If regulations are promulgated to regulate the
sulfur content of off-road diesel, we expect the sulfur requirement to be either
500 ppm, which is the current on-road limit, or 15 ppm, which will be the future
on-road limit. If the new off-road standard is 500 ppm, the capital expenditures
necessary for us to comply with the new diesel standards may be significantly
reduced because the Port Arthur refinery currently meets the 500 ppm
specifications. We would thus continue to have a market for our current diesel
production at Port Arthur, albeit a smaller and lower-priced market, and
therefore we could elect not to make any capital expenditures necessary to
comply with the new on-road standard. Depending upon the standard promulgated
for off-road diesel, if any, and the compliance strategy we adopt in conjunction
with the Premcor Refining Group, the estimate or our capital expenditures in the
aggregate through 2006 required to comply with the diesel standards utilizing
existing technologies may range from zero to $175 million. More than 90% of the
projected investment, if necessary, is expected to be incurred during 2004
through 2006 with the greatest concentration of spending occurring in 2005.
Cash Flows from Financing Activities
Cash flows provided by financing activities were zero for the nine-month
period ended September 30, 2001 compared to $184.0 million last year. The 2000
proceeds were comprised principally of borrowings under the bank senior loan
agreement and required pro-rata shareholder contributions received pursuant to
capital contribution agreements that were used to fund the heavy oil upgrade
project. The deferred financing costs in 2000 were associated with the filing of
documents with the Securities and Exchange Commission for the registration of
the 12 1/2 % senior secured notes. As of June 30, 2001, $37.4 million and $13.2
million was available to us through our bank senior loan agreement and capital
contribution agreements, respectively. During the third quarter, we decided not
to borrow the remaining portion of the bank senior loan agreement. Since the
obligation to fund the capital contributions was contingent upon the funding of
the bank senior loan agreement, we will not receive the unfunded capital
contribution commitments. The ability to draw any remaining funds under the
senior bank loan agreement and receive the remaining capital contribution
commitments expired upon the achievement of substantial reliability of the heavy
oil upgrade facility in September of 2001.
Funds generated from operating activities together with existing cash and
cash equivalents are expected to be adequate to fund existing requirements for
working capital and capital expenditure programs for the next year. Our
operating results are subject to rapid and wide fluctuations due to the
commodity nature of our feedstocks and products. However, there can be no
assurance that market conditions or actual operations will not be worse than
anticipated. Future working capital and discretionary and mandatory capital
expenditures may require additional debt or equity capital.
20
PART II - OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit
Number Description
------ -----------
3.01 Amended and Restated Certificate of Incorporation of Sabine
River Holding Corp. ("Sabine River") and the Certificate of
Amendment thereto dated August 11, 1999 (Incorporated by
reference to Exhibit 3.01(b) filed with the Company's
Registration Statement on Form S-4 (Registration No.
333-92871))
3.02 Amended and Restated By Laws of Sabine River (Incorporated by
reference to Exhibit 3.02(b) filed with the Company's
Registration Statement on Form S-4 (Registration No.
333-92871))
4.01 Indenture, dated as of August 19, 1999, among Sabine River,
Neches River Holding Corp. ("Neches River"), Port Arthur
Finance Corp. ("PAFC"), Port Arthur Coker Company L.P.
("PACC"), HSBC Bank USA, the capital markets trustee, and
Bankers Trust Company, as Collateral Trustee (Incorporated by
reference to Exhibit 4.01 filed with the Company's
Registration Statement on Form S-4 (Registration No.
333-92871))
4.02 Form of 12.50% Senior Secured Notes due 2009 (the "Exchange
Note") (Incorporated by reference to Exhibit 4.02 filed with
the Company's Registration Statement on Form S-4
(Registration No. 333-92871))
4.03 Common Security Agreement, dated as of August 19, 1999, among
PAFC, PACC, Sabine River, Neches River, Bankers Trust
Company, as Collateral Trustee and Depositary Bank, Deutsche
Bank AG, New York Branch ("Deutsche Bank"), as Administrative
Agent, Winterthur International Insurance Company Limited, an
English company ("Winterthur"), as Oil Payment Insurers
Administrative Agent and HSBC Bank USA, as Capital Markets
Trustee (Incorporated by reference to Exhibit 4.04 filed with
the Company's Registration Statement on Form S-4
(Registration No. 333-92871))
4.04 Transfer Restrictions Agreement, dated as of August 19, 1999,
among PAFC, PACC, Premcor Inc. (f/k/a Clark Refining Holdings
Inc.), Sabine River, Neches River, Blackstone Capital
Partners III Merchant Banking Fund L.P. ("BCP III"),
Blackstone Offshore Capital Partners III L.P. ("BOCP III"),
Blackstone Family Investment Partnership III ("BFIP III"),
Winterthur, as the Oil Payment Insurers Administrative agent,
Bankers Trust Company, as Collateral Trustee, Deutsche Bank,
as Administrative Agent and HSBC Bank USA, as Capital Markets
Trustee (Incorporated by reference to Exhibit 4.05 filed with
the Company's Registration Statement on Form S-4
(Registration No. 333-92871))
4.05 Intercreditor Agreement, dated as of August 19, 1999, among
Bankers Trust Company, as Collateral Trustee, Deutsche Bank,
as Administrative Agent, Winterthur, as Oil Payment Insurers
Administrative Agent and Debt Service Reserve Insurer and
HSBC Bank, as Capital Markets Trustee (Incorporated by
reference to Exhibit 4.06 filed with the Company's
Registration Statement on Form S-4 (Registration No.
333-92871))
(b) Reports on Form 8-K
Except as previously disclosed, the Company has not filed any
reports on Form 8-K during the period covered by this report and
up to and including the date of filing of this report.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Sabine River Holding Corp.
(Registrant)
/s/ Dennis R. Eichholz
---------------------------------------
Dennis R. Eichholz
Controller (Principal
Accounting Officer and
Duly Authorized Officer)
November 13, 2001
22