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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 1-14569
PLAINS ALL AMERICAN PIPELINE, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0582150
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
333 CLAY STREET, SUITE 2900
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(ZIP CODE)
(713) 646-4100
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ----------------------- ------------------------------------------
COMMON UNITS NEW YORK STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [_]
The aggregate value of the Common Units held by non-affiliates of the registrant
(treating all executive officers and directors of the registrant and holders of
10% or more of the Common Units outstanding, for this purpose, as if they may be
affiliates of the registrant) was approximately $640,433,291 on March 15, 2002,
based on $25.61 per unit, the closing price of the Common Units as reported on
the New York Stock Exchange on such date.
At March 15, 2002, there were outstanding 31,915,939 Common Units, 1,307,190
Class B Common Units and 10,029,619 Subordinated Units.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
2001 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PAGE
----
Part I
Items 1 and 2. Business and Properties................................ 1
Item 3. Legal Proceedings...................................... 25
Item 4. Submission of Matters to a Vote of Security Holders.... 26
PART II
Item 5. Market for the Registrant's Common Units and Related
Unitholder Matters.................................... 27
Item 6. Selected Financial and Operating Data.................. 29
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 32
Item 7a. Quantitative and Qualitative Disclosures About
Market Risks.......................................... 47
Item 8. Financial Statements and Supplementary Data............ 49
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................... 49
PART III
Item 10. Directors and Executive Officers of Our General
Partner............................................... 50
Item 11. Executive Compensation................................. 53
Item 12. Security Ownership of Certain Beneficial Owners
and Management........................................ 56
Item 13. Certain Relationships and Related Transactions......... 58
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K........................................... 65
FORWARD-LOOKING STATEMENTS
All statements, other than statements of historical fact, included in this
report are forward-looking statements, including, but not limited to, statements
identified by the words "anticipate," "believe," "estimate," "expect,"
"plan," "intend" and "forecast" and similar expressions and statements
regarding our business strategy, plans and objectives of our management for
future operations. These statements reflect our current views and those of our
general partner with respect to future events, based on what we believe are
reasonable assumptions. Certain factors could cause actual results to differ
materially from results anticipated in the forward-looking statements. The
factors include, but are not limited to:
. abrupt or severe production declines or production interruptions in outer
continental shelf production located offshore California and transported on
the All American Pipeline;
. the availability of adequate supplies of and demand for crude oil in the
areas in which we operate;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. successful integration and future performance of acquired assets;
. our ability to receive credit on satisfactory terms;
. shortages or cost increases of power supplies, materials or labor;
. the impact of current and future laws and governmental regulations;
. environmental liabilities that are not covered by an indemnity or insurance;
. fluctuations in the debt and equity markets; and
. general economic, market or business conditions.
Other factors described herein, or factors that are unknown or unpredictable,
could also have a material adverse effect on future results. See Item 7.
"Management's Discussion and Analysis--Risk Factors Related to Our Business".
Except as required by applicable securities laws, we do not intend to update
these forward-looking statements and information.
i
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
We are a publicly traded Delaware limited partnership (the "partnership")
engaged in interstate and intrastate marketing, transportation and terminalling
of crude oil and marketing of liquefied petroleum gas ("LPG"). We were formed in
September 1998 to acquire and operate the midstream crude oil business and
assets of Plains Resources Inc. and its wholly owned subsidiaries ("Plains
Resources") as a separate, publicly traded master limited partnership. We
completed our initial public offering in November 1998. Immediately after our
initial public offering, Plains Resources owned 100% of our general partner
interest and an overall effective ownership in the partnership of 57% (including
the 2% general partner interest and common and subordinated units owned by it).
In May 2001, senior management and a group of financial investors entered into
a transaction with Plains Resources to acquire control of the general partner
interest and a majority of the outstanding subordinated units. The transaction
closed in June 2001 and, for purposes of this report, is referred to as the
"General Partner Transition". As a result of this transaction, Plains Resources'
ownership in the general partner interest was reduced from 100% to 44%.
Additionally, as a result of this transaction and various equity offerings
conducted since the initial public offering, Plains Resources' overall effective
ownership has been reduced to approximately 29%. In addition, certain senior
officers of the general partner that previously were also officers of Plains
Resources terminated their affiliation with Plains Resources and now devote 100%
of their efforts to the management of the partnership.
The general partner interest is now held by Plains AAP, L.P., a Delaware
limited partnership. Plains All American GP LLC, a Delaware limited liability
company, is Plains AAP, L.P.'s general partner. Our operations and activities
are managed by, and our officers and personnel are employed by, Plains All
American GP LLC. Unless the context otherwise requires, we use the term "general
partner" to refer to both Plains AAP, L.P. and Plains All American GP LLC. We
use the phrase "former general partner" to refer to the subsidiary of Plains
Resources that formerly held the general partner interest.
Our operations are concentrated in Texas, Oklahoma, California and Louisiana
and in the Canadian provinces of Alberta, Saskatchewan and Manitoba, and can be
categorized into two primary business activities:
. Crude Oil Pipeline Transportation. We own and operate over 3,000 miles of
gathering and mainline crude oil pipelines located throughout the United
States and Canada. Our activities from pipeline operations generally consist
of transporting crude oil for a fee.
. Terminalling and Storage Activities and Gathering and Marketing Activities.
In connection with our terminalling and storage activities, we own and
operate approximately 11.5 million barrels of above-ground crude oil
terminalling and storage facilities, including the state-of-the-art, 3.1
million barrel crude oil terminalling and storage facility at Cushing,
Oklahoma (the "Cushing Terminal"). Cushing is the largest crude oil trading
hub in the United States and the designated delivery point for New York
Mercantile Exchange, or NYMEX, crude oil futures contracts (the "Cushing
Interchange"). Our terminalling and storage operations generate revenue
through a combination of storage and throughput charges to third parties. We
also utilize our storage tanks to counter-cyclically balance our gathering
and marketing operations and to execute different hedging strategies to lock
in profits and reduce the negative impact of crude oil market volatility. See
"--Crude Oil Volatility; Counter-Cyclical Balance; Risk Management".
Our gathering and marketing operations include:
. the purchase of crude oil at the wellhead and the bulk purchase of crude oil
at pipeline and terminal facilities;
. the transportation of crude oil on trucks, barges or pipelines, including our
own;
. the subsequent resale or exchange of crude oil at various points along the
crude oil distribution chain; and
. The purchase of LPG from producers, refiners and other marketers, and sale of
LPG to end users and retailers.
1
BUSINESS STRATEGY
Our business strategy is to capitalize on the regional crude oil supply and
demand imbalances that exist in the United States and Canada by combining the
strategic location and unique capabilities of our transportation and
terminalling assets with our extensive marketing and distribution expertise to
generate sustainable earnings and cash flow.
We intend to execute our business strategy by:
. increasing and optimizing throughput on our various pipeline and gathering
assets and realizing cost efficiencies through operational improvements and
potential strategic alliances;
. utilizing and expanding our Cushing Terminal and our other assets to service
the needs of refiners and to profit from merchant activities that take
advantage of crude oil pricing and quality differentials;
. pursuing strategic and accretive acquisitions of crude oil transportation
assets and businesses, including pipelines, gathering systems, terminalling
and storage facilities, gathering and marketing entities and other assets
that complement our existing asset base and distribution capabilities; and
. optimizing and expanding our Canadian operations to take advantage of
anticipated increases in the volume and qualities of crude oil produced in,
and exported from, Canada.
FINANCIAL STRATEGY
We believe that a major factor in our continued success will be our ability to
maintain a low cost of capital and access to capital markets. Since our
inception in 1998, we have consistently communicated to the financial community
our intention to maintain a strong credit profile that we believe is consistent
with our goal of achieving and maintaining an investment grade credit rating. We
have targeted a general credit profile with the following attributes:
. an average long-term debt-to-total capitalization ratio of approximately 60%
or less;
. an average long-term debt-to-EBITDA ratio of approximately 3.5x or less; and
. an average EBITDA-to-interest coverage ratio of approximately 3.3x or better.
As of December 31, 2001, we were within our targeted credit profile. In order
for us to maintain our target credit profile and achieve growth through
acquisitions, our strategy is to fund acquisitions using approximately equal
proportions of equity and debt. Because it is likely that acquisitions will
initially be financed using indebtedness and it is difficult to predict the
actual timing of accessing the market to raise equity, we may be temporarily,
from time to time, outside the parameters of our target credit profile until
such time as the equity is raised.
COMPETITIVE STRENGTHS
We believe we are well positioned to successfully execute our business
strategy due to the following competitive strengths:
. Our pipeline assets are strategically located and have additional capacity.
Our primary crude oil pipeline transportation and gathering assets are
located in prolific oil producing regions and are connected, directly or
indirectly, with our terminalling and storage assets that service major North
American refinery and distribution markets, where we have strong business
relationships. These assets are strategically positioned to maximize the
value of our crude oil by transporting it to major trading locations and
premium markets. Our pipeline networks possess additional capacity to respond
to increased demand.
. Our Cushing Terminal is strategically located, operationally flexible and
readily expandable. Our Cushing Terminal interconnects with the Cushing
Interchange's major inbound and outbound pipelines, providing access to both
foreign and domestic crude oil. The Cushing Terminal is the most modern
terminalling and storage facility at the Cushing Interchange, incorporating
(1) operational enhancements designed to safely and efficiently terminal,
store, blend and segregate large volumes and multiple varieties of crude oil
and (2) extensive environmental safeguards.
. Our business activities are counter-cyclically balanced. We believe that our
terminalling and storage activities and our gathering and marketing
activities are counter-cyclical. We believe that this balance of activities,
combined with the long-term nature of our pipeline transportation contracts,
has a stabilizing effect on our cash flow from operations.
. We possess specialized crude oil market knowledge. We believe our business
relationships with participants in all phases of the crude oil distribution
chain, from crude oil producers to refiners, as well as our own industry
expertise, provide us with a comprehensive understanding of the North
American crude oil markets.
. We have the financial flexibility to pursue expansion and acquisition
opportunities. We believe we have significant resources to finance strategic
expansion and acquisition opportunities, including our ability to issue
additional partnership units and to borrow under our bank credit facility.
2
. We have an experienced management team whose interests are aligned with those
of all of our stakeholders. Our executive management team has an average of
more than 20 years of industry experience, with an average of over 15 years
with us or our predecessors and affiliates, during which time there was
significant growth in our operations and profitability. As part of the
General Partner Transition, members of our senior management team acquired a
4% interest in our general partner. In addition, through restricted unit
grants and options, members of our senior management team have significant
contingent equity incentives that will vest only if we achieve specified
performance objectives.
PARTNERSHIP STRUCTURE AND MANAGEMENT
Our operations are conducted through, and our operating assets are owned by,
our subsidiaries. Our domestic operating limited partnerships are Plains
Marketing, L.P. and All American Pipeline, L.P. Our operations and activities
are managed by, and our officers and personnel are employed by, our general
partner. Our general partner does not receive a management fee or any other
compensation in connection with its management of our business, but it is
reimbursed for all direct and indirect expenses incurred on our behalf,
including employee compensation costs. Our Canadian operating limited
partnership is Plains Marketing Canada, L.P. Canadian personnel are employed by
its general partner, PMC (Nova Scotia) Company.
Our general partner has responsibility for conducting our business and
managing our operations, and owns all of the incentive distribution rights.
These rights provide that our general partner receives an increasing percentage
of cash distributions (in addition to its 2% general partner interest) as
distributions reach and exceed certain threshold levels. See Item 5. "Market for
the Registrant's Common Units and Related Unitholder Matters".
3
The chart below depicts the current organization and ownership of Plains All
American Pipeline, the operating partnerships and the subsidiaries.
[organization chart appears here]
4
ACQUISITIONS AND DISPOSITIONS
Coast/Lantern Acquisition
In March 2002, we completed the acquisition of substantially all of the
domestic crude oil pipeline, gathering, and marketing assets of Coast Energy
Group and Lantern Petroleum, divisions of Cornerstone Propane Partners, L.P. for
approximately $8.2 million in cash plus transactions costs. The principal assets
acquired, which are located in West Texas, include several gathering lines,
crude oil contracts and a small truck and trailer fleet.
Butte Acquisition
In February 2002, we acquired an approximate 22% equity interest in Butte Pipe
Line Company from Murphy Ventures, a wholly owned subsidiary of Murphy Oil
Corporation. The total cost of the acquisition, including various transaction
and related expenses, was approximately $8.0 million. Butte Pipe Line Company
owns the 373-mile Butte Pipeline System, principally a mainline transmission
system, that runs from Baker, Montana to Guernsey, Wyoming. At the time of
acquisition, the Butte Pipeline System transported approximately 60,000 barrels
per day of crude oil. The remaining 78% interest in the Butte Pipe Line Company
is owned by Equilon Pipeline Company LLC.
Wapella Acquisition
In December 2001, we completed the acquisition of the Wapella Pipeline System
from private investors for approximately $12.0 million including transaction
costs. In 2001, the Wapella Pipeline System delivered approximately 11,000
barrels per day of crude oil to the Enbridge Pipeline at Cromer, Manitoba. The
system is located in southeastern Saskatchewan and southwestern Manitoba. The
acquisition also includes approximately 21,500 barrels of crude oil storage
capacity located along the system as well as a truck terminal.
CANPET Energy Group, Inc.
In July 2001, we purchased substantially all of the assets of CANPET Energy
Group Inc., a Calgary-based Canadian crude oil and liquefied petroleum gas
marketing company, for approximately $42.0 million plus $25.0 million for
additional inventory owned by CANPET at the closing of the transaction.
Approximately $24.0 million of the purchase price, plus $25.0 million for the
additional inventory, was paid in cash at closing, and the remainder, which is
subject to various performance standards, will be paid in common units in April
2004 if the performance standards are met. The principal assets acquired include
a crude oil handling facility, a 130,000-barrel tank facility, LPG facilities,
existing business relationships and working capital of approximately $8.6
million.
Murphy Oil Company Ltd. Midstream Operations
In May 2001, we completed the acquisition of substantially all of the Canadian
crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil
Company Ltd. for approximately $161.0 million in cash including financing and
transaction costs. The purchase price included $6.5 million for excess inventory
in the systems. The principal assets acquired include approximately 450 miles
of crude oil and condensate mainlines (including dual lines on which condensate
is shipped for blending purposes and blended crude is shipped in the opposite
direction) and associated gathering and lateral lines, approximately 1.1 million
barrels of crude oil storage and terminalling capacity located primarily in
Kerrobert, Saskatchewan, approximately 254,000 barrels of pipeline linefill and
tank inventories, an inactive 108-mile mainline system and 121 trailers used
primarily for crude oil transportation. We have reactivated the 108-mile
mainline system and began shipping volumes in May of 2001.
Scurlock Acquisition
In May 1999, we completed the acquisition of Scurlock Permian LLC and certain
other pipeline assets from Marathon Ashland Petroleum LLC. Including working
capital adjustments and closing and financing costs, the cash purchase price was
approximately $141.7 million. Financing for the acquisition was provided through
$117.0 million of borrowings and the sale of 1.3 million Class B Common Units to
our former general partner for total cash consideration of $25.0 million.
Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum,
was engaged in crude oil transportation, gathering and marketing. The assets
acquired included approximately 2,300 miles of active pipelines, numerous
storage terminals and a fleet of trucks. The largest asset is an approximately
920-mile pipeline and gathering system located in the Spraberry Trend in West
Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton
Counties, Texas. The assets we acquired also included approximately one million
barrels of crude oil linefill.
5
West Texas Gathering System Acquisition
In July 1999, we completed the acquisition of the West Texas Gathering System
from Chevron Pipe Line Company for approximately $36.0 million, including
transaction costs. Financing for the amounts paid at closing was provided by a
draw under a previous credit facility. The assets acquired include approximately
420 miles of crude oil transmission mainlines, approximately 295 miles of
associated gathering and lateral lines, and approximately 2.9 million barrels of
tankage located along the system.
All American Pipeline Linefill Sale and Asset Disposition
In March 2000, we sold to a unit of El Paso Corporation ("El Paso") for $129.0
million the segment of the All American Pipeline that extends from Emidio,
California to McCamey, Texas. Except for minor third-party volumes, one of our
subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of
the pipeline since its predecessor acquired the line from the Goodyear Tire &
Rubber Company in July 1998. We realized net proceeds of approximately $124.0
million after the associated transaction costs and estimated costs to remove
equipment. We used the proceeds from the sale to reduce outstanding debt. We
recognized a gain of approximately $20.1 million in connection with the sale.
We had suspended shipments of crude oil on this segment of the pipeline in
November 1999. At that time, we owned approximately 5.2 million barrels of crude
oil in the segment of the pipeline. We sold this crude oil from November 1999 to
February 2000 for net proceeds of approximately $100.0 million, which were used
for working capital purposes. We recognized gains of approximately $28.1 million
and $16.5 million in 2000 and 1999, respectively, in connection with the sale of
the linefill.
PIPELINE OPERATIONS
We describe below our principal pipeline assets. All of our pipeline systems
are operated from one of two central control rooms with computer systems
designed to continuously monitor real-time operational data including
measurement of crude oil quantities injected in and delivered through the
pipelines, product flow rates and pressure and temperature variations. This
monitoring and measurement technology allows us to efficiently batch differing
crude oil types with varying characteristics through the pipeline systems. The
systems are designed to enhance leak detection capabilities, to sound automatic
alarms in the event of operational conditions outside of pre-established
parameters and to provide for remote-controlled shut-down of pump stations on
the pipeline systems. Pump stations, storage facilities and meter measurement
points along the pipeline systems are linked by telephone, satellite or radio
communication systems for remote monitoring and control, which reduces our
requirement for full time site personnel at most of these locations.
We perform scheduled maintenance on all of our pipeline systems and make
repairs and replacements when necessary or appropriate. We attempt to control
corrosion of the mainlines through the use of corrosion inhibiting chemicals
injected into the crude stream, external coatings and cathodic protection
systems. Maintenance facilities containing equipment for pipe repairs, spare
parts and trained response personnel are strategically located along the
pipelines and in concentrated operating areas. We believe that all of our
pipelines have been constructed and are maintained in all material respects in
accordance with applicable federal, state and local laws and regulations,
standards prescribed by the American Petroleum Institute and accepted industry
practice. See "--Regulation".
U. S. Pipeline Assets
All American Pipeline. The segment of the All American Pipeline that we
retained following the sale of the line to El Paso is a common carrier crude oil
pipeline system that transports crude oil produced from Outer Continental Shelf
("OCS") fields offshore California to locations in California. See "--All
American Pipeline Linefill Sale and Asset Disposition". This segment is subject
to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC")
(see "--Regulation-- Transportation Regulation"). As a common carrier, the All
American Pipeline offers transportation services to any shipper of crude oil,
provided that the crude oil tendered for transportation satisfies the conditions
and specifications contained in the applicable tariff.
We own and operate the segment of the system that extends approximately 10
miles from ExxonMobil's onshore facilities at Las Flores on the California coast
to Plains Resources' onshore facilities at Gaviota, California (24-inch diameter
pipe) and continues from Gaviota approximately 130 miles to our station in
Emidio, California (30-inch pipe). Between Gaviota and our Emidio Station, the
All American Pipeline interconnects with our San Joaquin Valley ("SJV")
Gathering System as well as various third-party intrastate pipelines, including
the Unocap Pipeline System, the Equilon Pipeline System and the Pacific
Pipeline.
The All American Pipeline currently transports OCS crude oil received at the
onshore facilities of the Santa Ynez field at Las Flores, California and the
onshore facilities of the Point Arguello field located at Gaviota, California.
ExxonMobil,
6
which owns all of the Santa Ynez production, and Plains Resources, Texaco and
Sun Operating L.P., which together own approximately one-half of the Point
Arguello production, have entered into transportation agreements committing to
transport all of their production from these fields on the All American
Pipeline. These agreements, which expire in August 2007, provide for a minimum
tariff with annual escalations based on specific composite indices. The
producers from the Point Arguello field who do not have contracts with us
currently have no other efficient means of transporting their production and,
therefore, ship their volumes on the All American Pipeline at the posted
tariffs. Volumes attributable to Plains Resources are purchased and sold to a
third party under our marketing agreement with Plains Resources before such
volumes enter the All American Pipeline. See Item 13. "Certain Relationships and
Related Transactions--Transactions with Related Parties." The third party pays
the same tariff as required in the transportation agreements. At December 31,
2001, the tariffs averaged $1.54 per barrel for deliveries to connecting
pipelines in California. The tariff was increased by approximately 11% effective
January 9, 2002. The agreements do not require these owners to transport a
minimum volume. For the year ended December 31, 2001, approximately $27.5
million, or 19.3% of our gross margin was attributable to the Santa Ynez field
and approximately $9.5 million, or 6.7%, was attributable to the Point Arguello
field. Transportation of volumes commenced from the Point Arguello field on the
All American Pipeline in 1991 and from the Santa Ynez field in 1994.
The table below sets forth the historical volumes received from both of these
fields for the last five years.
YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(BARRELS IN THOUSANDS)
Average daily volumes received from
Point Arguello (at Gaviota) 18 18 20 26 30
Santa Ynez (at Las Flores) 51 56 59 68 85
-- -- -- -- ---
Total 69 74 79 94 115
== == == == ===
A wholly owned subsidiary of Plains Resources is the operator of record for
the Point Arguello Unit. All of the volumes attributable to Plains Resources'
interests are committed for transportation on the All American Pipeline and are
subject to our marketing agreement with Plains Resources. We expect that there
will continue to be natural production declines from each of these fields as the
underlying reservoirs are depleted. See Item 13. "Certain Relationships and
Related Transactions--Transactions with Related Parties--General".
A significant portion of the Partnership's gross margin is derived from
pipeline transportation margins associated with these two fields. The relative
contribution to our gross margin from these fields has decreased from
approximately 46% in the second half of 1998 to 26% in 2001, as the
partnership has grown and diversified through acquisitions and organic
expansions and as a result of declines in volumes produced and transported from
these fields, offset somewhat by an increase in pipeline tariffs. Over the last
several years, transportation volumes received from the Santa Ynez and Point
Arguello fields have declined from 92,000 and 60,000 average daily barrels,
respectively, in 1995 to 51,000 and 18,000 average daily barrels, respectively,
for the year ended December 31, 2001. Although the rate of decline has decreased
over the last three years, we expect that there will continue to be natural
production declines from each of these fields as the underlying reservoirs are
depleted. A 5,000 barrel per day decline in volumes shipped from these fields
would result in a decrease in annual pipeline tariff revenues of approximately
$2.8 million.
SJV Gathering System. The SJV Gathering System is a proprietary pipeline
system that runs through the heart of the San Joaquin Valley. As a proprietary
pipeline, the SJV Gathering System is not subject to common carrier regulations.
The SJV Gathering System was constructed in 1987 with a design capacity of
approximately 140,000 barrels per day. The system consists of a 16-inch pipeline
that originates at the Belridge station and extends 45 miles south to a
connection with the All American Pipeline at the Pentland station.
The San Joaquin Valley is one of the most prolific oil producing regions in
the continental United States, producing approximately 552,000 barrels per day
of crude oil during the first nine months of 2001, which accounted for
approximately 77% of total California production (excluding OCS) and 11% of the
total production in the lower 48 states.
7
The following table reflects the historical production for the San Joaquin
Valley as well as total California production (excluding OCS volumes) as
reported by the California Division of Oil and Gas for the past five years.
YEAR ENDED DECEMBER 31,
--------------------------------
2001(1) 2000 1999 1998 1997
------- ---- ---- ---- ----
(BARRELS IN THOUSANDS)
Average daily volumes
San Joaquin Valley production (2) 552 570 562 592 584
Total California production
(excluding OCS volumes) 716 741 734 781 781
---------------
(1) Reflects information through September 2001.
(2) Consists of production from California Division of Oil and Gas District
IV.
The SJV Gathering System is connected to several fields, including the South
Belridge, Elk Hills and Midway Sunset fields, three of the seven largest
producing fields in the lower 48 states. We lease a pipeline that
provides us access to the Lost Hills field. The SJV Gathering System also
includes approximately 630,000 barrels of tank capacity, which can be used to
facilitate movements along the system as well as to support our other
activities.
The table below sets forth the historical volumes received into the SJV
Gathering System for the past five years.
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(BARRELS IN THOUSANDS)
Total average daily volumes 61 60 84 85 91
West Texas Gathering System. The West Texas Gathering System is a common
carrier crude oil pipeline system located in the heart of the Permian Basin
producing area. The West Texas Gathering System has lease gathering facilities
in Crane, Ector, Upton, Ward and Winkler counties. The West Texas Gathering
System was originally built by Gulf Oil Corporation in the late 1920's, expanded
during the late 1950's and updated during the mid 1990's. The West Texas
Gathering System provides us with considerable flexibility, as major segments
are bi-directional and allow us to move crude oil between three of the major
trading locations in West Texas. The West Texas Gathering System has the
capability to transport approximately 190,000 barrels per day.
Total system volumes were approximately 82,000 barrels per day in 2001. System
volumes include lease volumes, volumes from connecting carriers and volumes from
truck injection stations. Lease volumes gathered into the system averaged
approximately 39,000 barrels per day in 2001. Chevron USA has agreed to
transport its equity crude oil production from fields connected to the West
Texas Gathering System on the system through July 2011 (currently representing
approximately 22,000 barrels per day, or 56% of total system gathering volumes
and 27% of the total system volumes). Other large producers connected to the
gathering system include Burlington Resources, Devon Energy, Anadarko, Oxy,
Bass, and TotalFinaElf. Volumes from connecting carriers, including ExxonMobil
and Phillips, average approximately 30,000 barrels per day. At the time of the
acquisition, truck injection stations were limited and provided less than 1,000
barrels per day. We have since installed 16 truck injection stations on the West
Texas Gathering System. Truck injection stations provided an average of 13,000
barrels per day in 2001. Our trucks are used to pick up crude oil produced in
the areas adjacent to the West Texas Gathering System and deliver these volumes
into the pipeline. These additional injection stations have allowed us to reduce
the distance of our truck hauls in this area, increase the utilization of our
pipeline assets and reduce our operating costs. The West Texas Gathering System
also includes approximately 2.5 million barrels of tank capacity located along
the pipeline system.
Sabine Pass Pipeline System. The Sabine Pass Pipeline System, acquired in the
Scurlock acquisition, is a common carrier crude oil pipeline system. The primary
purpose of the Sabine Pass Pipeline System is to gather crude oil from onshore
facilities of offshore production near Johnson's Bayou, Louisiana, and deliver
it to tankage and barge loading facilities in Sabine Pass, Texas. The Sabine
Pass Pipeline System consists of approximately 34 miles of pipe ranging from 4
to 10 inches
8
in diameter and has a throughput capacity of approximately 26,000
barrels of Louisiana light sweet crude oil per day. In 2001, the system
transported approximately 20,000 barrels of crude oil per day. The Sabine Pass
Pipeline System also includes 245,000 barrels of tank capacity located along the
pipeline.
Ferriday Pipeline System. The Ferriday Pipeline System, acquired in the
Scurlock acquisition, is a common carrier crude oil pipeline system located in
eastern Louisiana and western Mississippi. The Ferriday Pipeline System consists
of approximately 570 miles of pipe ranging from 2 inches to 12 inches in
diameter. In 2001, the Ferriday Pipeline System delivered approximately 11,500
barrels per day of crude oil (including truck volumes rerouted from a third-
party pipeline undergoing modifications) to third-party pipelines that supplied
refiners in the Midwest. The Ferriday Pipeline System also includes
approximately 332,000 barrels of tank capacity located along the pipeline.
In November 1999, we completed the construction of an 8-inch pipeline
underneath the Mississippi River that connects our Ferriday Pipeline System in
western Mississippi with the portion of the system located in eastern Louisiana.
This connection provides us with bi-directional capability to access additional
markets and enhances our ability to service our pipeline customers and take
advantage of additional high margin merchant activities.
Dollarhide Pipeline System. The Dollarhide Pipeline System, acquired from
Unocal Pipeline Company in October 2001, is a common carrier pipeline system
that is located in West Texas. In 2001, the Dollarhide Pipeline System delivered
approximately 5,000 barrels of crude oil per day into the West Texas Gathering
System. The system also includes approximately 215,000 barrels of crude oil
storage capacity along the system and in Midland.
Spraberry Pipeline System. The Spraberry Pipeline System, acquired in the
Scurlock acquisition, is a proprietary pipeline system that gathers crude oil
from the Spraberry Trend of West Texas and transports it to Midland, Texas,
where it interconnects with the West Texas Gathering System and other pipelines.
The Spraberry Pipeline System consists of approximately 920 miles of pipe of
varying diameter, and has a throughput capacity of approximately 50,000 barrels
of crude oil per day. The Spraberry Trend is one of the largest producing areas
in West Texas, and we are one of the largest gatherers in the Spraberry Trend.
The Spraberry Pipeline System gathered approximately 38,000 barrels per day of
crude oil in 2001. The Spraberry Pipeline System also includes approximately
173,000 barrels of tank capacity located along the pipeline. The margins that we
generate using the system are included in our Marketing, Gathering, Terminalling
and Storage segment.
East Texas Pipeline System. The East Texas Pipeline System, acquired in the
Scurlock acquisition, is a proprietary crude oil pipeline system. In 2001, it
gathered approximately 21,000 barrels per day of crude oil in East Texas and
transported approximately 23,000 barrels per day of crude oil to Crown Central's
refinery in Longview, Texas. The deliveries to Crown Central are subject to a
throughput and deficiency agreement, which extends through 2004. The East Texas
Pipeline System also includes approximately 221,000 barrels of tank capacity
located along the pipeline. The margins that we generate from the gathered
barrels on the system are included in our Marketing, Gathering, Terminalling and
Storage segment.
Illinois Basin Pipeline System. The Illinois Basin Pipeline System, acquired
with the Scurlock acquisition, consists of common carrier pipeline and gathering
systems and truck injection facilities in southern Illinois. The Illinois Basin
Pipeline System consists of approximately 80 miles of pipe of varying diameter.
In 2001, the system delivered approximately 4,100 barrels per day of crude oil
to third-party pipelines that supplied refiners in the Midwest. Approximately
3,300 barrels per day of the supply on this system are from fields operated by
Plains Resources.
Canadian Pipeline Assets
Manito Pipeline System. The Manito Pipeline System, acquired in the Murphy
acquisition, is a National Energy Board ("NEB") regulated system located in
Saskatchewan, Canada. The Manito Pipeline System is a 101-mile crude oil
pipeline and a parallel 101-mile condensate pipeline that connects the North
Saskatchewan Pipeline System and multiple gathering lines to the Enbridge system
at Kerrobert. The Manito Pipeline System volumes were approximately 66,000
barrels per day of crude oil in 2001.
Milk River Pipeline System. The Milk River Pipeline System, acquired in the
Murphy acquisition, is an NEB-regulated system located in Alberta, Canada. The
Milk River Pipeline System consists of three parallel 11-mile crude oil
pipelines that connect the Bow River Pipeline in Alberta to the Centex Pipeline
at the United States border. The Milk River Pipeline System transported
approximately 91,000 barrels per day of crude oil in 2001.
North Saskatchewan Pipeline System. The North Saskatchewan Pipeline System,
acquired in the Murphy acquisition, is an NEB-regulated system located in
Saskatchewan, Canada. The North Saskatchewan Pipeline System is a 34-mile crude
oil pipeline and a parallel 34-mile condensate pipeline that connects to the
Manito Pipeline at Dulwich. In 2001, the North Saskatchewan Pipeline System
delivered approximately 6,500 barrels per day of crude oil into the Manito
pipeline. Our ownership interest in the North Saskatchewan Pipeline System is
approximately 36%.
9
Cactus Lake/Bodo Pipeline System. The Cactus Lake/Bodo Pipeline System,
acquired in the Murphy acquisition, is an NEB-regulated system located in
Alberta and Saskatchewan, Canada. The Cactus Lake/Bodo Pipeline System is a 55-
mile crude oil pipeline and a parallel 55-mile condensate pipeline that connects
to our storage and terminalling facility at Kerrobert. In 2001, the Cactus
Lake/Bodo Pipeline System transported approximately 33,000 barrels per day of
crude oil. Our ownership interest in the Cactus Lake/Bodo Pipeline System varies
from a low of 13.125% to a high of 76.25%, depending upon the particular segment
of the system.
Wascana Pipeline System. The Wascana Pipeline System, acquired in the Murphy
acquisition, is a common carrier system located in Saskatchewan, Canada. The
Wascana Pipeline System is a 108-mile crude oil pipeline that connects to the
Equilon Pipeline at Raymond, Montana. In 2001, the Wascana Pipeline System
transported approximately 13,000 barrels per day of crude oil.
Wapella Pipeline System. The Wapella Pipeline System is an NEB-regulated
system located in southeastern Saskatchewan and southwestern Manitoba. In 2001,
the Wapella Pipeline System delivered approximately 11,000 barrels per day of
crude oil to the Enbridge Pipeline at Cromer, Manitoba. The system also includes
approximately 21,500 barrels of crude oil storage capacity.
TERMINALLING, STORAGE, MARKETING AND GATHERING OPERATIONS
Terminalling and Storage Activities
We own approximately 11.5 million barrels of terminalling and storage assets,
including tankage associated with our pipeline and gathering systems. Our
storage and terminalling operations increase the margins in our business of
purchasing and selling crude oil and also generate revenue through a combination
of storage and throughput fees from third parties. Storage fees are generated
when we lease tank capacity to third parties. Terminalling fees, also referred
to as throughput fees, are generated when we receive crude oil from one
connecting pipeline and redeliver crude oil to another connecting carrier in
volumes that allow the refinery to receive its crude oil on a ratable basis
throughout a delivery period. Both terminalling and storage fees are generally
earned from:
. refiners and gatherers that segregate or custom blend crudes for refining
feedstocks;
. pipeline operators, refiners or traders that need segregated tankage for
foreign cargoes;
. traders who make or take delivery under NYMEX contracts; and
. producers and resellers that seek to increase their marketing alternatives.
The tankage that is used to support our arbitrage activities positions us to
capture margins in a contango market (when the oil prices for future deliveries
are higher than current prices) or as the market switches from contango to
backwardation (when the oil prices for future deliveries are lower than current
prices). See "--Crude Oil Volatility; Counter-Cyclical Balance; Risk
Management".
Our most significant terminalling and storage asset is our Cushing Terminal.
The terminal was constructed in 1993, and expanded by approximately 55% in 1999,
to capitalize on the crude oil supply and demand imbalance in the Midwest. The
imbalance was caused by the continued decline of regional production supplies,
increasing imports and an inadequate pipeline and terminal infrastructure. The
Cushing Terminal is also used to support and enhance the margins associated with
our merchant activities relating to our lease gathering and bulk trading
activities. See "--Gathering and Marketing Activities--Bulk Purchases".
The Cushing Terminal currently has total storage capacity of approximately 3.1
million barrels. We have recently announced the 1.1 million barrel Phase II and
the 1.1 million barrel Phase III expansions of our Cushing Terminal facility. We
expect the Phase II expansion will be completed in mid-2002 and the Phase III
expansion will be completed in late 2002 or early 2003. Giving effect to these
expansions, the capacity of the Cushing Terminal will increase approximately 71%
to a total of approximately 5.3 million barrels. Upon completion of the Phase II
and Phase III expansion projects, the Cushing Terminal will consist of fourteen
100,000 barrel tanks, four 150,000 barrel tanks and twelve 270,000 barrel tanks,
which are used to store and terminal crude oil. The Cushing Terminal also
includes a pipeline manifold and pumping system that has an estimated daily
throughput capacity of approximately 800,000 barrels per day. The pipeline
manifold and pumping system is designed to support more than ten million barrels
of tank capacity. The Cushing Terminal is connected to the major pipelines and
other terminals in the Cushing Interchange through pipelines that range in size
from 10 inches to 24 inches in diameter.
The Cushing Terminal is a state-of-the-art facility designed to serve the
needs of refiners in the Midwest. Since its original construction in 1993, we
have experienced an increase in the volumes as well as the varieties of foreign
and domestic crude oil transported through the Cushing Interchange. Anticipating
these increases, we incorporated certain attributes into the design of the
Cushing Terminal including:
10
. multiple, smaller tanks to facilitate simultaneous handling of multiple crude
varieties in accordance with normal pipeline batch sizes;
. dual header systems connecting most tanks to the main manifold system to
facilitate efficient switching between crude grades with minimal
contamination;
. bottom drawn sumps that enable each tank to be efficiently drained down to
minimal remaining volumes to minimize crude contamination and maintain crude
integrity during changes of service;
. mixer(s) on each tank to facilitate blending crude grades to refinery
specifications; and
. a manifold and pump system that allows for receipts and deliveries with
connecting carriers at their maximum operating capacity.
As a result of incorporating these attributes into the design of the Cushing
Terminal, we believe we are favorably positioned to serve the needs of Midwest
refiners and to handle the increase in varieties of crude transported through
the Cushing Interchange.
The Cushing Terminal also incorporates numerous environmental and operational
safeguards. We believe that our terminal is the only one at the Cushing
Interchange in which each tank has a secondary liner (the equivalent of double
bottoms), leak detection devices, secondary seals and above-ground pipelines.
Each tank is cathodically protected. Like the pipeline systems we operate, the
Cushing Terminal is operated by a computer system designed to monitor real time
operational data. In addition, each tank is equipped with an audible and visual
high level alarm system to prevent overflows; a double seal floating roof
designed to minimize air emissions and prevent the possible accumulation of
potentially flammable gases between fluid levels and the roof of the tank; and a
foam dispersal system that, in the event of a fire, is fed by a fully-automated
fire water distribution network.
The Cushing Interchange is the largest wet barrel trading hub in the U.S. and
the delivery point for crude oil futures contracts traded on the NYMEX. The
Cushing Terminal has been designated by the NYMEX as an approved delivery
location for crude oil delivered under the NYMEX crude oil futures contract. As
the NYMEX delivery point and a cash market hub, the Cushing Interchange serves
as a primary source of refinery feedstock for the Midwest refiners and plays an
integral role in establishing and maintaining markets for many varieties of
foreign and domestic crude oil.
The following table sets forth throughput volumes for our terminalling and
storage operations, and quantity of tankage leased to third parties from 1997
through 2001.
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- --------- ---------
(BARRELS IN THOUSANDS)
Throughput volumes
(average daily volumes)
Cushing Terminal 94 59 72 69 69
Ingleside Terminal 5 8 11 11 8
----- ----- ----- ----- ---
Total 99 67 83 80 77
===== ===== ===== ===== ===
Storage leased to third parties
(average monthly volumes)
Cushing Terminal 2,136 1,437 1,743 890 414
Ingleside Terminal 220 220 232 260 254
----- ----- ----- ----- ---
Total 2,356 1,657 1,975 1,150 668
===== ===== ===== ===== ===
Gathering and Marketing Activities
Crude Oil. The majority of our gathering and marketing activities are in
Texas, Louisiana and California and the provinces of Alberta, Saskatchewan and
Manitoba. These activities include:
. purchasing crude oil from producers at the wellhead and in bulk from
aggregators at major pipeline interconnects and trading locations;
. transporting this crude oil on our own assets or, when necessary or cost
effective, assets owned and operated by third parties;
. exchanging this crude oil for another grade of crude oil or at a different
geographic location, as appropriate, in order to maximize margins or meet
contract delivery requirements; and
. marketing crude oil to refiners or other resellers.
11
We purchase crude oil from many independent producers and believe that we have
established broad-based relationships with crude oil producers in our areas of
operations. For the year ended December 31, 2001, we purchased approximately
375,000 barrels per day of crude oil directly at the wellhead. Gathering and
marketing activities are characterized by large volumes of transactions with
lower margins relative to pipeline and terminalling and storage operations.
In the period immediately following the disclosure of our unauthorized trading
losses in 1999, a significant number of our suppliers and trading partners
reduced or eliminated the open credit previously extended to us. Consequently,
the amount of letters of credit we needed to support the level of our crude oil
purchases then in effect increased significantly. In addition, the cost of
letters of credit increased under our credit facility, and some of our purchase
contracts were terminated. For the year 2001, we believe that the effects of the
loss on our cost of credit and operations were minimal and the requirement for
us to issue letters of credit has reduced to levels lower than existed before
the unauthorized trading loss. See "--Unauthorized Trading Losses."
The following table shows the average daily volume of our lease gathering and
bulk purchases from 1997 through 2001.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------
2001 (2) 2000 1999 (1) 1998 1997
--------------------------------------------------------------------------
(BARRELS IN THOUSANDS)
Lease Gathering 375 262 265 88 71
Bulk Purchases 54 28 138 98 49
---------- ---------- ---------- ---------- ---------
Total 429 290 403 186 120
========== ========== ========== ========== =========
- ---------------
(1) Includes average daily volumes from Scurlock Permian since May 1, 1999,
extrapolated for the entire year.
(2) Includes average daily volumes from the Murphy acquisition and the CANPET
acquisition since April 1 and July 1, respectively, extrapolated for the
entire year.
Crude Oil Purchases. We purchase crude oil from producers under contracts that
range in term from a thirty-day evergreen to three years. In a typical
producer's operation, crude oil flows from the wellhead to a separator where the
petroleum gases are removed. After separation, the crude oil is treated to
remove water, sand and other contaminants and is then moved into the producer's
on-site storage tanks. When the tank is full, the producer contacts our field
personnel to purchase and transport the crude oil to market. We use our truck
fleet, gathering pipelines, third-party pipelines and barges to transport the
crude oil to market. We own or lease approximately 300 trucks used for gathering
crude oil.
We have a marketing agreement with Plains Resources under which we are the
exclusive marketer/purchaser for all of Plains Resources' equity crude oil
production. The marketing agreement provides that we will purchase for resale at
market prices all of Plains Resources' equity crude oil production for which we
charge a fee of $0.20 per barrel. This fee is subject to adjustment every three
years based upon then-existing market conditions. The marketing agreement will
terminate upon a "change of control" of Plains Resources or our general partner.
In November 2001, the marketing agreement automatically extended for an
additional three-year period. See Item 13. "Certain Relationships and Related
Transactions--Transactions with Related Parties."
Bulk Purchases. In addition to purchasing crude oil at the wellhead from
producers, we purchase crude oil in bulk at major pipeline terminal points. This
production is transported from the wellhead to the pipeline by major oil
companies, large independent producers or other gathering and marketing
companies. We purchase crude oil in bulk when we believe additional
opportunities exist to realize margins further downstream in the crude oil
distribution chain. The opportunities to earn additional margins vary over time
with changing market conditions. Accordingly, the volumes and margins associated
with our bulk purchases will fluctuate from period to period.
Crude Oil Sales. The marketing of crude oil is complex and requires detailed
current knowledge of crude oil sources and end markets and a familiarity with a
number of factors including grades of crude oil, individual refinery demand for
specific grades of crude oil, area market price structures for the different
grades of crude oil, location of customers, availability of transportation
facilities and timing and costs (including storage) involved in delivering crude
oil to the appropriate customer. We sell our crude oil to major integrated oil
companies, independent refiners and other resellers in various types of sale and
exchange transactions, at market prices for terms ranging generally from one
month to three years.
12
We establish a margin for crude oil we purchase by selling crude oil for
physical delivery to third party users, such as independent refiners or major
oil companies, or by entering into a future delivery obligation with respect to
futures contracts on the NYMEX. Through these transactions, we establish on a
monthly basis a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. From time to time, we enter
into fixed price delivery contracts, floating price collar arrangements,
financial swaps and crude oil futures and options contracts as hedging devices.
Except for pre-defined inventory positions as discussed under "--Crude Oil
Volatility; Counter-Cyclical Balance; Risk Management" below, our policy is
generally (i) to purchase only crude oil for which we have a market, (ii) to
structure our sales contracts so that crude oil price fluctuations do not
materially affect the gross margin we receive and (iii) not to acquire and hold
crude oil, futures contracts or other derivative products for the purpose of
speculating on crude oil price changes that might expose us to indeterminable
losses. See "--Crude Oil Volatility; Counter-Cyclical Balance; and Risk
Management". In November 1999, we discovered that this policy was violated, and
we incurred $174.0 million in unauthorized trading losses, including estimated
associated costs and legal expenses. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses. See
"--Unauthorized Trading Losses".
Crude Oil Exchanges. We pursue exchange opportunities to enhance margins
throughout the gathering and marketing process. When opportunities arise to
increase our margin or to acquire a grade of crude oil that more nearly matches
our physical delivery requirement or the preferences of our refinery customers,
we exchange physical crude oil with third parties. These exchanges are effected
through contracts called exchange or buy-sell agreements. Through an exchange
agreement, we agree to buy crude oil that differs in terms of geographic
location, grade of crude oil or physical delivery schedule from crude oil we
have available for sale. Generally, we enter into exchanges to acquire crude oil
at locations that are closer to our end markets, thereby reducing transportation
costs and increasing our margin. We also exchange our crude oil to be physically
delivered at an earlier or later date, if the exchange is expected to result in
a higher margin net of storage costs, and enter into exchanges based on the
grade of crude oil, which includes such factors as sulfur content and specific
gravity, in order to meet the quality specifications of our physical delivery
contracts.
Producer Services. Crude oil purchasers who buy from producers compete on the
basis of competitive prices and highly responsive services. Through our team of
crude oil purchasing representatives, we maintain our ongoing relationships with
producers in the United States and Canada. We believe that our ability to offer
high-quality field and administrative services to producers is a key factor in
our ability to maintain volumes of purchased crude oil and to obtain new
volumes. High-quality field services include efficient gathering capabilities,
availability of trucks, willingness to construct gathering pipelines where
economically justified, timely pickup of crude oil from tank batteries at the
lease or production point, accurate measurement of crude oil volumes received,
avoidance of spills and effective management of pipeline deliveries. Accounting
and other administrative services include securing division orders (statements
from interest owners affirming the division of ownership in crude oil purchased
by us), providing statements of the crude oil purchased each month, disbursing
production proceeds to interest owners and calculation and payment of ad valorem
and production taxes on behalf of interest owners. In order to compete
effectively, we must maintain records of title and division order interests in
an accurate and timely manner for purposes of making prompt and correct payment
of crude oil production proceeds, together with the correct payment of all
severance and production taxes associated with such proceeds.
Liquefied Petroleum Gas. We also gather and market LPG throughout the United
States and Canada, concentrated primarily in Washington, California, Kansas,
Michigan, Texas, Montana, Nebraska and the Canadian provinces of Alberta and
Ontario. These activities include:
. purchasing LPG (propane and butane) from producers at gas plants and in bulk
at major pipeline terminal points and storage locations;
. transporting the LPG via common carrier pipelines, railcars and trucks to our
own terminals and our customers' facilities for subsequent resale to retail
and wholesale customers; and
. exchanging product to other locations to maximize margins and/or to meet
contract delivery requirements.
We purchase LPG from many producers and believe that we have established long-
term, broad based relationships with LPG producers in our areas of operation. We
purchase LPG directly from gas plants, major pipeline interconnects and storage
locations. Gathering and marketing activities for LPG typically consist of
smaller transactions in terms of volume, but generate higher margins per barrel
relative to crude oil transactions.
LPG Purchases. We purchase LPG from producers, refiners, and other LPG
marketing companies under contracts that range from immediate delivery to one
year in term. In a typical producer's or refiner's operation, LPG that is
produced at the gas plant or refinery is fractionated into propane and butanes
and then purchased by us for movement via tank truck, railcar or pipeline.
13
In addition to purchasing LPG at the gas plant or refinery from producers, we
also purchase LPG in bulk at major pipeline terminal points and storage
facilities from major oil companies, large independent producers or other LPG
marketing companies. We purchase LPG in bulk when we believe additional
opportunities exist to realize margins further downstream in our LPG
distribution chain. The opportunities to earn additional margins vary over time
with changing market conditions. Accordingly, the margins associated with our
bulk purchases will fluctuate from period to period. Our bulk purchasing
activities are concentrated in Kansas, Texas, Alberta and Ontario.
LPG Sales. The marketing of LPG is complex and requires detailed current
knowledge of LPG sources and end markets and a familiarity with a number of
factors including the various modes and availability of transportation, area
market prices and timing and costs of delivering LPG to customers.
We sell LPG primarily to end users and retailers, and limited volumes to other
marketers. Propane is sold to the small independent retailers who then transport
the product via bobtail truck to the residential consumer for home heating and
to some light industrial users such as forklift operators. Butane is used by
refiners for gasoline blending and as a diluent for the movement of conventional
heavy oil production. Butane demand for use as heavy oil diluent has increased
as supplies of Canadian condensate have declined.
We establish a margin for LPG that we purchase by taking the propane component
and transporting it in large volume, via various transportation modes, to our
controlled terminals where we deliver the propane to our retailer customers for
subsequent delivery to their individual heating customers. We also create margin
by selling propane for future physical delivery to third party users, such as
retailers and industrial users. Through these transactions, we seek to maintain
a position that is substantially balanced between propane purchases and sales
and future delivery obligations. From time to time, we enter into floating price
collar arrangements, financial swaps and crude oil and LPG-related futures
contracts as hedging devices. Our policy is generally to purchase only LPG for
which we have a market, and to structure our sales contracts so that LPG
fluctuations do not materially affect the gross margin we receive. Margin is
created on the butane purchased by delivering large volumes during the short
refinery blending season through the use of our extensive leased railcar fleet
and the use of third party storage facilities. We also create margin on butane
by capturing the difference in price between condensate and butane when butane
is used to replace condensate as a diluent for the movement of heavy oil
production.
LPG Exchanges. We pursue exchange opportunities to enhance margins throughout
the gathering and marketing process. When opportunities arise to increase our
margin or to acquire a volume of LPG that more nearly matches our physical
delivery requirement or the preferences of our customers, we exchange physical
LPG with third parties. These exchanges are affected through contracts called
exchange or buy-sell agreements. Through an exchange agreement, we agree to buy
LPG that differs in terms of geographic location, type of LPG or physical
delivery schedule from LPG we have available for sale. Generally, we enter into
exchanges to acquire LPG at locations that are closer to our end markets in
order to meet the delivery specifications of our physical delivery contracts.
Credit. Our merchant activities involve the purchase of crude oil for resale
and require significant extensions of credit by our suppliers of crude oil. In
order to assure our ability to perform our obligations under crude oil purchase
agreements, various credit arrangements are negotiated with our crude oil
suppliers. Such arrangements include open lines of credit directly with us and
standby letters of credit issued under our letter of credit facility. At
December 31, 2001, we had letters of credit outstanding aggregating
approximately $30.1 million. Generally, letters of credit are issued for a
period of up to 70 days. See Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources."
When we market crude oil, we must determine the amount, if any, of the line of
credit to be extended to any given customer. If we determine that a customer
should receive a credit line, we must then decide on the amount of credit that
should be extended. Since our typical sales transactions can involve tens of
thousands of barrels of crude oil, the risk of nonpayment and nonperformance by
customers is a major consideration in our business. We believe our sales are
made to creditworthy entities or entities with adequate credit support.
We also have credit risk with respect to our sales of LPG; however, because
our sales are typically in relatively small amounts to individual customers, we
do not believe that we have material concentration of credit risk. Typically, we
enter into annual contracts to sell LPG on a forward basis, as well as sell LPG
on a current basis to local distributors and retailers. In certain cases our
customers prepay for their purchases, in amounts ranging from 10% to 100% of
their contracted amounts. Generally, sales of LPG are settled within seven days
of the sale.
Crude Oil Volatility; Counter-Cyclical Balance; Risk Management
Crude oil prices have historically been very volatile and cyclical, with NYMEX
benchmark prices ranging from as high as $40.00 per barrel to as low as $10.00
per barrel over the last 12 years. Gross margin from terminalling and storage
activities is dependent on the throughput volume of crude oil stored, capacity
leased to third parties, capacity that we use, and the level of other fees
generated at our terminalling and storage facilities. Gross margin from our
gathering and marketing
14
activities is dependent on our ability to sell crude oil at a price in excess of
our aggregate cost. These operations are not directly affected by the absolute
level of crude oil prices, but are affected by overall levels of supply and
demand for crude oil and relative fluctuations in market-related indices.
During periods when the demand for crude oil is weak on a relative basis (as
was the case in the first quarter of 1999 and the last nine months of 2001), the
market for crude oil is often in contango, meaning that the price of crude oil
for future deliveries is higher than current prices. A contango market has a
generally negative impact on marketing margins, but is favorable to the storage
business, because storage owners at major trading locations (such as the Cushing
Interchange) can simultaneously purchase production at current prices for
storage and sell at higher prices for future delivery.
When there is a higher demand than supply of crude oil in the near term (as
was the case in the last nine months of 1999, 2000 and the first quarter of
2001), the market is backwardated, meaning that the price of crude oil for
future deliveries is lower than current prices. A backwardated market has a
positive impact on marketing margins because crude oil gatherers can capture a
premium for prompt deliveries. In this environment, there is little incentive
to store crude oil as current prices are above future delivery prices.
The periods in between a backwardated market and a contango market are
referred to as transition periods. Depending on the overall duration of these
transition periods, how we have allocated our assets to particular strategies
and the time length of our crude oil purchase and sale contracts and storage
lease agreements, these transition periods may have either an adverse or
beneficial affect on our aggregate gross margin. A prolonged transition from a
backwardated market to a contango market (essentially a market that is neither
in pronounced backwardation or contango) represents the most difficult
environment for our gathering, marketing, storage and terminalling activities.
When the market is in contango, we will use our tankage to improve our gathering
margins by storing crude we have purchased for delivery in future months that
are selling at a higher price. In a backwardated market, we use and lease less
storage capacity but increased marketing margins provide an offset to this
reduced cash flow. We believe that the combination of our terminalling and
storage activities and gathering and marketing activities provides a counter-
cyclical balance that has a stabilizing effect on our operations and cash flow.
References to counter-cyclical balance elsewhere in this report are referring to
this relationship between our terminalling and storage activities and our
gathering and marketing activities in transitioning crude oil markets.
As use of the financial markets for crude oil has increased by producers,
refiners, utilities, other users of energy and trading entities, risk management
strategies, including those involving price hedges using NYMEX futures contracts
and derivatives, have become increasingly important in creating and maintaining
margins. Such hedging techniques require significant resources dedicated to
managing these positions. Our risk management policies and procedures are
designed to monitor both NYMEX and over-the-counter positions and physical
volumes, grades, locations and delivery schedules to ensure that our hedging
activities are implemented in accordance with such policies. We have a risk
management function that has direct responsibility and authority for our risk
policies and our trading controls and procedures and certain other aspects of
corporate risk management.
Our policy is to purchase only crude oil for which we have a market, and to
structure our sales contracts so that crude oil price fluctuations do not
materially affect the gross margin we receive. Except for inventory transactions
not to exceed 500,000 barrels, we do not acquire and hold crude oil futures
contracts or other derivative products for the purpose of speculating on crude
oil price changes that might expose us to indeterminable losses.
As a result of production and delivery variances associated with our lease
purchase activities, from time to time we experience net unbalanced positions.
In connection with managing these positions and maintaining a constant presence
in the marketplace, both necessary for our core business, we engage in this
controlled trading program for up to 500,000 barrels. This activity is
monitored independently by our risk management function and must take place
within predefined limits and authorizations. In order to hedge margins
involving our physical assets and manage risks associated with our crude oil
purchase and sale obligations we use derivative instruments, including futures
and over-the-counter instruments. In analyzing our risk management activities,
we draw a distinction between enterprise-level risks and trading-related risks.
Enterprise-level risks are those that underlie our core businesses and may be
managed based on whether there is value in doing so. Conversely, trading-
related risks (the risks involved in trading in the hopes of generating an
increased return) are not inherent in the core business; rather, the risks arise
as a result of engaging in the trading activity. We have a Risk Management
Committee that approves all new risk management strategies through a formal
process. With the partial exception of the limited program not to exceed
500,000 barrels, our approved strategies are intended to mitigate enterprise-
level risks that are inherent in our core businesses of gathering and marketing
and storage.
Although the intent of our risk-management strategies is to hedge our margin,
not all of our derivatives qualify for hedge accounting. In such instances,
changes in the fair values of these derivatives will receive mark-to-market
treatment in current earnings, and result in greater potential for earnings
volatility than in the past. This accounting treatment is discussed further
under Notes 2 and 9 of "Notes to Consolidated Financial Statements".
15
GEOGRAPHIC DATA
Prior to 2001, all of our revenues were derived from, and our assets located
in, the United States. During 2001, we expanded into Canada. See "--Acquisitions
and Dispositions." Set forth below is a table of 2001 revenues and long-lived
assets attributable to these geographic areas (in thousands):
REVENUES
United States $6,149,788
Canada $ 718,427
LONG-LIVED ASSETS
United States $ 567,551
Canada $ 188,207
OPERATING ACTIVITIES
For information with respect to our pipeline activities and terminalling and
storage and gathering and marketing activities, see "--Pipeline Operations", "--
Terminalling, Storage, Marketing and Gathering Operations" and Note 16 in the
Notes to Consolidated Financial Statements appearing elsewhere in this report.
CUSTOMERS
Customers accounting for more than 10% of sales for the periods indicated are
as follows:
PERCENTAGE
YEAR ENDED DECEMBER 31,
----------------------------
2001 2000 1999
---- ---- ----
Marathon Ashland Petroleum 11% 12% -
Sempra Energy Trading Corporation - - 22%
Koch Oil Company - - 19%
All of the customers above pertain to our marketing, gathering, terminalling
and storage segment. We believe that the loss of the customer included above for
2001 would have only a short-term impact on our operating results. There can be
no assurance, however, that we would be able to identify and access a
replacement market at comparable margins.
COMPETITION
Competition among pipelines is based primarily on transportation charges,
access to producing areas and demand for the crude oil by end users. We believe
that high capital requirements, environmental considerations and the difficulty
in acquiring rights of way and related permits make it unlikely that competing
pipeline systems comparable in size and scope to our pipeline systems will be
built in the foreseeable future. However, to the extent there are already third-
party owned pipelines with excess capacity in the vicinity of our operations, we
will be exposed to significant competition based on the incremental cost of
moving an incremental barrel of crude oil.
We face intense competition in our terminalling and storage activities and
gathering and marketing activities. Our competitors include other crude oil
pipelines, the major integrated oil companies, their marketing affiliates and
independent gatherers, brokers and marketers of widely varying sizes, financial
resources and experience. Some of these competitors have capital resources many
times greater than ours and control substantially greater supplies of crude oil.
REGULATION
Our operations are subject to extensive regulations. Many federal, state,
provincial and local departments and agencies are authorized by statute to
issue and have issued laws and regulations binding on the oil pipeline industry
and its individual participants. The failure to comply with such rules and
regulations can result in substantial penalties. The regulatory burden on the
oil pipeline industry increases our cost of doing business and, consequently,
affects our profitability. However, we do not believe that we are affected in a
significantly different manner by these laws and regulations than are our
competitors. Due to the myriad of complex federal, state, provincial and local
regulations that may affect us, directly or indirectly, you should not rely on
the following discussion of certain laws and regulations as an exhaustive
review of all regulatory considerations affecting our operations.
16
Pipeline Regulation
Our petroleum pipelines in the United States are subject to regulation by the
U.S. Department of Transportation ("DOT") with respect to the design,
installation, testing, construction, operation, replacement, and management of
pipeline facilities. In addition, we must permit access to and copying of
records, and must make certain reports available and provide information as
required by the Secretary of Transportation. Comparable regulation exists in
some states in which we conduct intrastate common carrier or private pipeline
operations.
Pipeline safety issues are currently receiving significant attention in
various political and administrative arenas at both the state and federal
levels. For example, recent federal rule changes require pipeline operators to:
(i) develop and maintain a written qualification program for individuals
performing covered tasks on pipeline facilities, and (ii) establish pipeline
integrity management programs. In particular, during 2000, the DOT adopted new
regulations requiring operators of interstate pipelines to develop and follow an
integrity management program that provides for continual assessment of the
integrity of all pipeline segments that could affect so-called "high consequence
areas", including high population areas, drinking water areas and ecological
resource areas that are unusually sensitive to environmental damage from a
pipeline release, and commercially navigable waterways. Segments of our
pipelines are located in high consequence areas. Under this new rule, we are
required to evaluate pipeline conditions by means of periodic internal
inspection, pressure testing, or other equally effective assessment means and to
correct identified anomalies. If, as a result of our evaluation process, we
determine that there is a need to provide further protection to high consequence
areas, then we will be required to implement additional prevention and
mitigation risk control measures for our pipelines, including enhanced damage
prevention programs, corrosion control program improvements, leak detection
system enhancements, installation of emergency flow restricting devices, and
emergency preparedness improvements. Under this new rule, we will also be
required to evaluate and, as necessary, improve our management and analysis
processes for integrating available integrity-related data relating to our
pipeline segments and to remediate potential problems found as a result of the
required assessment and evaluation process. Based on currently available
information, our preliminary estimate of the costs to implement this program
over the next five years ranges between $5 million and $10 million. Although we
believe that our pipeline operations are in substantial compliance with
applicable Pipeline Safety Act requirements, these developments renew the
prospect of incurring significant expenses if additional safety requirements are
imposed that exceed our current pipeline control system capabilities.
States are largely preempted by federal law from regulating pipeline safety
but may assume responsibility for enforcing federal intrastate pipeline
regulations and inspection of intrastate pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety. We do
not anticipate any significant problems in complying with applicable state laws
and regulations in those states in which we operate.
Transportation Regulation
General Interstate Regulation. Our interstate common carrier pipeline
operations are subject to rate regulation by the Federal Energy Regulatory
Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce
Act requires that tariff rates for petroleum pipelines, which includes crude
oil, as well as refined product and petrochemical pipelines, be just and
reasonable and non-discriminatory.
State Regulation. Our intrastate pipeline transportation activities are
subject to various state laws and regulations, as well as orders of regulatory
bodies.
Canadian Regulation. The Partnership's Canadian pipeline assets are subject to
regulation by the National Energy Board and by provincial agencies in
Saskatchewan and Alberta. With respect to a pipeline over which it has
jurisdiction, each of these agencies has the power, upon application by a third
party, to determine the rates we are allowed to charge for transportation on
such pipeline. In such circumstances, if the relevant regulatory agency
determines that the applicable terms and conditions of service are not just and
reasonable, the agency can amend the offending provisions of an existing
transportation contract.
Energy Policy Act of 1992 and Subsequent Developments. In October 1992,
Congress passed the Energy Policy Act of 1992 (the "Act"), which among other
things, required the FERC to issue rules establishing a simplified and generally
applicable ratemaking methodology for petroleum pipelines and to streamline
procedures in petroleum pipeline proceedings. The FERC responded to this mandate
by issuing several orders, including Order No. 561. Beginning January 1, 1995,
Order No. 561 enables petroleum pipelines to change their rates within
prescribed ceiling levels that are tied to an inflation index. Rate increases
made pursuant to the indexing methodology are subject to protest, but such
protests must show that the portion of the rate increase resulting from
application of the index is substantially in excess of the pipeline's increase
in costs. If the indexing methodology results in a reduced ceiling level that is
lower than a pipeline's filed rate, Order No. 561 requires the pipeline to
reduce its rate to comply with the lower ceiling. A pipeline must, as a general
rule, utilize the indexing
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methodology to change its rates. The FERC, however, retained cost-of-service
ratemaking, market-based rates, and settlement as alternatives to the indexing
approach, which alternatives may be used in certain specified circumstances.
The Act deemed petroleum pipeline rates in effect for the 365-day period
ending on the date of enactment of the Act or that were in effect on the 365th
day preceding enactment and had not been subject to complaint, protest or
investigation during the 365-day period to be just and reasonable under the
Interstate Commerce Act. Generally, complaints against such "grandfathered"
rates may only be pursued if the complainant can show that a substantial change
has occurred since enactment in either the economic circumstances or the nature
of the services which were a basis for the rate or that a provision of the
tariff is unduly discriminatory or preferential.
In a proceeding involving Lakehead Pipe Line Company, Limited Partnership
(Opinion No. 397), FERC concluded that there should not be a corporate income
tax allowance built into a petroleum pipeline's rates to reflect income
attributable to noncorporate partners since noncorporate partners, unlike
corporate partners, do not pay a corporate income tax. On January 13, 1999, the
FERC issued Opinion No. 435 in a proceeding involving SFPP, L.P., which, among
other things, affirmed Opinion No. 397's determination that there should not be
a corporate income tax allowance built into a petroleum pipeline's rates to
reflect income attributable to noncorporate partners. On rehearing, the FERC
affirmed its position; however, additional rehearing requests on other matters
remain pending. Petitions for review of Opinion No. 435 and subsequent FERC
opinions in the case are before the D.C. Circuit Court of Appeals, but are being
held in abeyance pending FERC action on the remaining rehearing requests. Once
the rehearing process is completed, the FERC's position on the income tax
allowance and on other rate issues could be subject to judicial review.
Our Pipelines. The FERC generally has not investigated rates on its own
initiative when those rates have not been the subject of a protest or complaint
by a shipper. Substantially all of our gross margins on transportation are
produced by rates that are either grandfathered or set by agreement of the
parties. Rates for OCS crude are set by transportation agreements with shippers
that do not expire until 2007 and provide for a minimum tariff with annual
escalation. The FERC has twice approved the agreed OCS rates, although
application of the indexing method would have required their reduction. When
these OCS agreements expire in 2007, they will be subject to renegotiation or to
any of the other methods for establishing rates under Order No. 561. As a
result, we believe that the rates now in effect can be sustained, although no
assurance can be given that the rates currently charged would ultimately be
upheld if challenged. In addition, we do not believe that an adverse
determination on the tax allowance issue in the SFPP, L.P. proceeding would have
a detrimental impact upon our current rates.
Trucking Regulation
We operate a fleet of trucks to transport crude oil and oilfield materials as
a private, contract and common carrier. We are licensed to perform both
intrastate and interstate motor carrier services. As a motor carrier, we are
subject to certain safety regulations issued by the Department of
Transportation. The trucking regulations cover, among other things, driver
operations, maintaining log books, truck manifest preparations, the placement of
safety placards on the trucks and trailer vehicles, drug and alcohol testing,
safety of operation and equipment, and many other aspects of truck operations.
We are also subject to the Occupational Safety and Health Act, as amended
("OSHA"), with respect to our trucking operations.
The Partnership's trucking assets in Canada are subject to regulation by
provincial agencies in the provinces in which they are operated. These
regulatory agencies do not set freight rates, but do establish and administer
rules and regulations relating to other matters including equipment and driver
licensing, equipment inspection, hazardous materials and safety.
ENVIRONMENTAL REGULATION
General
Numerous federal, state and local laws and regulations governing the discharge
of materials into the environment or otherwise relating to the protection of the
environment affect our operations and costs. In particular, our activities in
connection with storage and transportation of crude oil and other liquid
hydrocarbons and our use of facilities for treating, processing or otherwise
handling hydrocarbons and wastes are subject to stringent environmental laws and
regulations. As with the industry generally, compliance with existing and
anticipated laws and regulations increases our overall cost of business,
including our capital costs to construct, maintain and upgrade equipment and
facilities. Although these regulations affect our capital expenditures and
earnings, we believe that they do not affect our competitive position because
our competitors that comply with such laws and regulations are similarly
affected. Environmental laws and regulations have historically been subject to
change, and we are unable to predict the ongoing cost to us of complying with
these laws and regulations or the future impact of such laws and regulations on
our operations. Violation of these environmental laws and regulations and any
associated permits can result in the imposition of significant administrative,
civil and criminal penalties, injunctions and construction bans or delays. A
discharge of hydrocarbons or hazardous substances into the environment could, to
the extent such event is not insured, subject us to substantial expense,
including both the cost to comply with
18
applicable laws and regulations and claims made by neighboring landowners and
other third parties for personal injury and property damage.
Water
The Oil Pollution Act, as amended ("OPA"), was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972, as amended
("FWPCA"), and other statutes as they pertain to prevention and response to oil
spills. The OPA subjects owners of facilities to strict, joint and potentially
unlimited liability for containment and removal costs, natural resource damages,
and certain other consequences of an oil spill, where such spill is into
navigable waters, along shorelines or in the exclusive economic zone of the U.S.
The OPA establishes a liability for onshore facilities of $350.0 million;
however, a party cannot take advantage of this liability limit if the spill is
caused by gross negligence or willful misconduct or resulted from a violation of
a federal safety, construction, or operating regulation. If a party fails to
report a spill or cooperate in the cleanup, the liability limits likewise do not
apply. In the event of an oil spill into navigable waters, substantial
liabilities could be imposed upon us. States in which we operate have also
enacted similar laws. Regulations have been or are currently being developed
under OPA and state laws that may also impose additional regulatory burdens on
our operations. We believe that we are in substantial compliance with applicable
OPA requirements.
The FWPCA imposes restrictions and strict controls regarding the discharge of
pollutants into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA imposes substantial
potential liability for the costs of removal, remediation and damages. We
believe that compliance with existing permits and compliance with foreseeable
new permit requirements will not have a material adverse effect on our financial
condition or results of operations.
Some states maintain groundwater protection programs that require permits for
discharges or operations that may impact groundwater conditions. We believe that
we are in substantial compliance with these state requirements.
Air Emissions
Our operations are subject to the Federal Clean Air Act, as amended, and
comparable state and local statutes. We believe that our operations are in
substantial compliance with these statutes in all states in which we operate.
Amendments to the Federal Clean Air Act enacted in late 1990 (the "1990
Federal Clean Air Act Amendments") as well as recent or soon to be adopted
changes to state implementation plans for controlling air emissions in regional
non-attainment areas require or will require most industrial operations in the
U.S. to incur capital expenditures in order to meet air emission control
standards developed by the U.S. Environmental Protection Agency (the "EPA") and
state environmental agencies. In addition, the 1990 Federal Clean Air Act
Amendments include a new operating permit for major sources ("Title V permits"),
which applies to some of our facilities. We will be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with obtaining or maintaining permits and approvals
addressing air emission related issues. Although we can give no assurances, we
believe implementation of the 1990 Federal Clean Air Act Amendments will not
have a material adverse effect on our financial condition or results of
operations.
Solid Waste
We generate wastes, including hazardous wastes, that are subject to the
requirements of the federal Resource Conservation and Recovery Act ("RCRA"), and
comparable state statutes. The EPA is considering the adoption of stricter
disposal standards for non-hazardous wastes, including oil and gas wastes. We
are not currently required to comply with a substantial portion of the RCRA
requirements because our operations generate minimal quantities of hazardous
wastes. However, it is possible that additional wastes, which could include
wastes currently generated as non-hazardous wastes during operations, will in
the future be designated as "hazardous wastes". Hazardous wastes are subject to
more rigorous and costly disposal requirements than are non-hazardous wastes.
Such changes in the regulations could result in additional capital expenditures
or operating expenses for us as well as the industry in general.
Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), also known as "Superfund", and comparable state laws impose
liability, without regard to fault or the legality of the original act, on
certain classes of persons that contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the site or sites where the release occurred and companies that disposed of, or
arranged for the disposal of, the hazardous substances found at the site. Under
CERCLA, such persons may be subject to joint and several liability for the costs
of cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources, and for the costs of certain
health studies. CERCLA also authorizes the EPA and, in some instances, third
parties to act in response to threats to the public health or the environment
and to seek to recover from the responsible classes
19
of persons the costs they incur. It is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment. In the course of our ordinary operations, we may generate waste
that falls within CERCLA's definition of a "hazardous substance". We may be
jointly and severally liable under CERCLA for all or part of the costs required
to clean up sites at which such hazardous substances have been disposed of or
released into the environment.
We currently own or lease, and have in the past owned or leased, properties
where hydrocarbons are being or have been handled. Although we have utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us or on or under other locations where these
wastes have been taken for disposal. In addition, many of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously disposed
wastes (including wastes disposed of or released by prior owners or operators),
to clean up contaminated property (including contaminated groundwater) or to
perform remedial plugging operations to prevent future contamination. We are
currently involved in remediation activities at a number of sites, which involve
potentially significant expense. See "--Environmental Remediation".
OSHA
We are subject to the requirements of OSHA, and comparable state statutes that
regulate the protection of the health and safety of workers. In addition, the
OSHA hazard communication standard requires that certain information be
maintained about hazardous materials used or produced in operations and that
this information be provided to employees, state and local government
authorities and citizens. We believe that our operations are in substantial
compliance with OSHA requirements, including general industry standards, record
keeping requirements and monitoring of occupational exposure to regulated
substances.
Endangered Species Act
The Endangered Species Act, as amended ("ESA"), restricts activities that may
affect endangered species or their habitats. While certain of our facilities are
in areas that may be designated as habitat for endangered species, we believe
that we are in substantial compliance with the ESA. However, the discovery of
previously unidentified endangered species could cause us to incur additional
costs or operation restrictions or bans in the affected area.
Hazardous Materials Transportation Requirements
The DOT regulations affecting pipeline safety require pipeline operators to
implement measures designed to reduce the environmental impact of oil discharge
from onshore oil pipelines. These regulations require operators to maintain
comprehensive spill response plans, including extensive spill response training
for pipeline personnel. In addition, DOT regulations contain detailed
specifications for pipeline operation and maintenance. We believe our operations
are in substantial compliance with such regulations. See "--Pipeline
Regulation".
ENVIRONMENTAL REMEDIATION
In connection with our acquisition of Scurlock Permian, we identified a number
of areas of potential environmental exposure. Under the terms of our acquisition
agreement, Marathon Ashland is fully indemnifying us for areas of environmental
exposure which were identified at the time of the acquisition, including any and
all liabilities associated with two superfund sites at which it is alleged
Scurlock Permian deposited waste oils as well as any potential liability for
hydrocarbon soil and water contamination at a number of Scurlock Permian
facilities. For environmental liabilities which were not identified at the time
of the acquisition but which occurred prior to the closing, we have agreed to
pay the costs relating to matters that are under $25,000. Our liabilities
relating to matters discovered prior to May 2003 and that exceed $25,000, is
currently limited to an aggregate of $0.5 million, with Marathon Ashland
indemnifying us for any excess amounts. Marathon Ashland's indemnification
obligations for identified sites extend indefinitely while its obligations for
non-identified sites extend to matters discovered within four years of the date
of acquisition (May 12, 1999) of Scurlock Permian. While we do not believe that
our liability, if any, for environmental contamination associated with our
Scurlock Permian assets will be material, there can be no assurance in that
regard. In any event, should we be found liable, we believe that our
indemnification from Marathon Ashland should prevent such liability from having
a material adverse effect on our financial condition, results of operations or
cash flows.
In connection with our acquisition of the West Texas Gathering System, we
agreed to be responsible for pre-acquisition environmental liabilities up to an
aggregate amount of $1.0 million, while Chevron Pipe Line Company agreed to
remain solely responsible for liabilities which are discovered prior to July
2002 which exceed this $1.0 million threshold. During our pre-acquisition
investigation, we identified a number of sites along our West Texas Gathering
System on which there are
20
hydrocarbon contaminated soils. While the total cost of remediation of these
sites has not yet been determined, we believe our indemnification arrangement
with Chevron Pipe Line Company should prevent such costs from having a material
adverse effect on our financial condition, results of operations or cash flows.
From 1994 to 1997 (prior to our acquisition in 1999), our Venice, Louisiana
terminal experienced several releases of crude oil and jet fuel into the soil.
The Louisiana Department of Environmental Quality has been notified of the
releases. Marathon Ashland has performed some soil remediation related to the
releases and retained liability for these conditions. The extent of the
contamination at the sites is uncertain and there is a potential for groundwater
contamination. We do not expect expenditures related to this terminal to be
material, although we can provide no assurances in that regard.
During 1997, the All American Pipeline experienced a leak in a segment of its
pipeline in California which resulted in an estimated 12,000 barrels of crude
oil being released into the soil. Immediate action was taken to repair the
pipeline leak, contain the spill and to recover the released crude oil. We have
expended approximately $400,000 to date in connection with this spill and do not
expect any additional expenditures to be material, although we can provide no
assurances in that regard.
Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and groundwater
underlying the site due to activities on the property. We are undertaking a
voluntary state-administered remediation of the contamination on the property to
determine the extent of the contamination. We have spent approximately $140,000
to date in investigating the contamination at this site. We do not anticipate
the total additional costs related to this site to exceed $250,000, although no
assurance can be given that the actual cost could not exceed such estimate.
We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover releases that were previously
unidentified. While we maintain an extensive inspection program designed to
prevent and, as applicable, to detect and address such releases promptly,
damages and liabilities incurred due to any future environmental releases from
our assets may substantially affect our business.
OPERATIONAL HAZARDS AND INSURANCE
A pipeline, terminal or other facilities may experience damage as a result of
an accident or natural disaster. These hazards can cause personal injury and
loss of life, severe damage to and destruction of property and equipment,
pollution or environmental damage and suspension of operations. We maintain
insurance of various types that we consider to be adequate to cover our
operations and properties. The insurance covers all of our assets in amounts
considered reasonable. The insurance policies are subject to deductibles that we
consider reasonable and not excessive. Our insurance does not cover every
potential risk associated with operating pipelines, terminals and other
facilities, including the potential loss of significant revenues. Consistent
with insurance coverage generally available to the industry, our insurance
policies provide limited coverage for losses or liabilities relating to
pollution, with broader coverage for sudden and accidental occurrences. The
events of September 11 and their overall effect on the insurance industry may
have a general adverse impact on availability and cost of coverage. We currently
maintain insurance for acts of terrorism on the majority of our assets and
operations. Many of our current policies expire on June 1, 2002. Due to the
events of September 11, 2001, we believe that many insurers will exclude acts of
terrorism from future insurance policies or make the cost for this coverage
prohibitive.
Since the terrorist attacks, the United States Government has issued warnings
that energy assets (including our nation's pipeline infrastructure) may be a
future target of terrorist organizations. These developments expose our
operations and assets to increased risks. Any future terrorist attacks on our
facilities, those of our customers and, in some cases, those of our competitors,
could have a material adverse effect on our business.
The occurrence of a significant event not fully insured or indemnified
against, or the failure of a party to meet its indemnification obligations,
could materially and adversely affect our operations and financial condition. We
believe that we are adequately insured for public liability and property damage
to others with respect to our operations. With respect to all of our coverage,
no assurance can be given that we will be able to maintain adequate insurance in
the future at rates we consider reasonable.
TITLE TO PROPERTIES
Substantially all of our pipelines are constructed on rights-of-way granted by
the apparent record owners of such property and in some instances the rights-of-
way are revocable at the election of the grantor. In many instances, lands over
which rights-of-way have been obtained are subject to prior liens that have not
been subordinated to the right-of-way grants. In some cases, not all of the
apparent record owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of majority interests
have been obtained. We have obtained permits from public authorities to cross
over or under, or to lay facilities in or along water courses, county roads,
municipal streets and state highways, and in some instances, the permits are
revocable at the election of the grantor. We have also obtained permits from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at
21
the grantor's election. In some cases, property for pipeline purposes was
purchased in fee. All of the pump stations are located on property owned in fee
or property under long-term leases. In certain states and under certain
circumstances, we have the right of eminent domain to acquire rights-of-way and
lands necessary for our common carrier pipelines.
Some of the leases, easements, rights-of-way, permits and licenses transferred
to us, upon our formation in 1998 and in connection with acquisitions we have
made since that time, required the consent of the grantor to transfer such
rights, which in certain instances is a governmental entity. We believe that we
have obtained the third-party consents, permits and authorizations as are
sufficient for the transfer to us of the assets necessary for us to operate our
business in all material respects as described in this report. With respect to
any consents, permits or authorizations that have not yet been obtained, we
believe that the consents, permits or authorizations will be obtained within a
reasonable period, or that the failure to obtain the consents, permits or
authorizations will have no material adverse effect on the operation of our
business.
We believe that we have satisfactory title to all of our assets. Although
title to such properties are subject to encumbrances in certain cases, such as
customary interests generally retained in connection with acquisition of real
property, liens related to environmental liabilities associated with historical
operations, liens for current taxes and other burdens and minor easements,
restrictions and other encumbrances to which the underlying properties were
subject at the time of acquisition by our predecessor or us, we believe that
none of such burdens will materially detract from the value of such properties
or from our interest therein or will materially interfere with their use in the
operation of our business.
EMPLOYEES
To carry out our operations, our general partner or its affiliates employed
approximately 1,000 employees at December 31, 2001. None of the employees of our
general partner were represented by labor unions, and our general partner
considers its employee relations to be good.
SUMMARY OF TAX CONSIDERATIONS
The tax consequences of ownership of common units depends in part on the
owner's individual tax circumstances. However, the following is a brief summary
of material tax consequences of owning and disposing of common units.
Partnership Status; Cash Distributions
We are classified for federal income tax purposes as a partnership based upon
our meeting certain requirements imposed by the Internal Revenue Code (the
"Code") which we must meet each year. The owners of common units are considered
partners in the partnership so long as they do not loan their common units to
others to cover short sales or otherwise dispose of those units. Accordingly, we
pay no federal income taxes, and a common unitholder is required to report on
the unitholder's federal income tax return the unitholder's share of our income,
gains, losses and deductions. In general, cash distributions to a common
unitholder are taxable only if, and to the extent that, they exceed the tax
basis in the common units held.
PARTNERSHIP ALLOCATIONS
In general, our income and loss is allocated to the general partner and the
unitholders for each taxable year in accordance with their respective percentage
interests in the partnership (including, with respect to the general partner,
its incentive distribution right), as determined annually and prorated on a
monthly basis and subsequently apportioned among the general partner and the
unitholders of record as of the opening of the first business day of the month
to which they relate, even though unitholders may dispose of their units during
the month in question. A unitholder is required to take into account, in
determining federal income tax liability, the unitholder's share of income
generated by us for each taxable year of the partnership ending within or with
the unitholder's taxable year, even if cash distributions are not made to the
unitholder. As a consequence, a unitholder's share of our taxable income (and
possibly the income tax payable by the unitholder with respect to such income)
may exceed the cash actually distributed to the unitholder by us. At any time
distributions are made on the common units in excess of distributions on the
subordinated units, or incentive distributions are made to the general partner,
gross income will be allocated to the recipient to the extent of those
distributions.
Basis of Common Units
A unitholder's initial tax basis for a common unit is generally the amount
paid for the common unit. A unitholder's basis is generally increased by the
unitholder's share of our income and decreased by the unitholder's share of our
losses and distributions.
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Limitations on Deductibility of Partnership Losses
In the case of taxpayers subject to the passive loss rules (generally,
individuals and closely held corporations), any partnership losses are only
available to offset future income generated by us and cannot be used to offset
income from other activities, including passive activities or investments. Any
losses unused by virtue of the passive loss rules may be fully deducted if the
unitholder disposes of all of the unitholder's common units in a taxable
transaction with an unrelated party.
Section 754 Election
We have made the election provided for by Section 754 of the Code, which will
generally result in a unitholder being allocated income and deductions
calculated by reference to the portion of the unitholder's purchase price
attributable to each asset of the partnership.
Disposition of Common Units
A unitholder who sells common units will recognize gain or loss equal to the
difference between the amount realized and the adjusted tax basis of those
common units. A unitholder may not be able to trace basis to particular common
units for this purpose. Thus, distributions of cash from us to a unitholder in
excess of the income allocated to the unitholder will, in effect, become taxable
income if the unitholder sells the common units at a price greater than the
unitholder's adjusted tax basis even if the price is less than the unitholder's
original cost. A portion of the amount realized (whether or not representing
gain) will be ordinary income.
Foreign, State, Local and Other Tax Considerations
In addition to federal income taxes, unitholders will likely be subject to
other taxes, such as foreign, state and local income taxes, unincorporated
business taxes, and estate, inheritance or intangible taxes that are imposed by
the various jurisdictions in which a unitholder resides or in which we do
business or own property. We own property and conduct business in five provinces
in Canada as well as in most states in the United States. All but four of those
states and all of the provinces currently impose a personal income tax that
would generally require a unitholder to file a return and pay taxes in that
state or province, as well as in Canada. Of the states in which we primarily do
business, only Texas does not have a personal income tax. In certain states, tax
losses may not produce a tax benefit in the year incurred (if, for example, we
have no income from sources within that state) and also may not be available to
offset income in subsequent taxable years. Some states may require us, or we