Back to GetFilings.com
================================================================================
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
================================================================================
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
17
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.
22
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 may
elect, to withhold a percentage of income from amounts to be distributed to a
unitholder. Withholding, the amount of which may be more or less than a
particular unitholder's income tax liability owed to the state, may not relieve
the nonresident unitholder from the obligation to file an income tax return.
Amounts withheld may be treated as if distributed to unitholders for purposes of
determining the amounts distributed by us.
It is the responsibility of each prospective unitholder to investigate the
legal and tax consequences, under the laws of Canada and those states and
localities, of the unitholder's investment in us. Further, it is the
responsibility of each unitholder to file all U.S. federal, Canadian, state and
local tax returns that may be required of the unitholder.
Ownership of Common Units by Tax-Exempt Organizations and Certain Other
Investors
An investment in common units by tax-exempt organizations (including IRAs and
other retirement plans), regulated investment companies (mutual funds) and
foreign persons raises issues unique to such persons. Virtually all of our
income allocated to a unitholder that is a tax-exempt organization is unrelated
business taxable income and, thus, is taxable to such a unitholder. Furthermore,
no significant amount of our gross income is qualifying income for purposes of
determining whether a unitholder will qualify as a regulated investment company,
and a unitholder who is a nonresident alien, foreign corporation or other
foreign person is regarded as being engaged in a trade or business in the United
States as a result of ownership of a common unit and, thus, is required to file
federal income tax returns and to pay tax on the unitholder's share of our
taxable income. Finally, distributions to foreign unitholders are subject to
federal income tax withholding.
Tax Shelter Registration
The Code generally requires that "tax shelters" be registered with the
Secretary of the Treasury. We are registered as a tax shelter with the Secretary
of the Treasury. Our tax shelter registration number is 99061000009. Issuance of
the registration number does not indicate that an investment in the partnership
or the claimed tax benefits has been reviewed, examined or approved by the IRS.
23
Unauthorized Trading Losses
Background
In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $174.0
million, which includes estimated associated costs and legal expenses. A full
investigation into the unauthorized trading activities by outside legal counsel
and independent accountants and consultants determined that the vast majority of
the losses occurred from March through November 1999, and the impact warranted a
restatement of previously reported financial information for 1999 and 1998.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses.
Normally, as we purchase crude oil, we establish a margin by selling crude oil
for physical delivery to third parties, or by entering into future delivery
obligations with respect to futures contracts. The employee in question violated
our policy of maintaining a substantially balanced position between purchases
and sales (or future delivery obligations) by negotiating one side of a
transaction without negotiating the other, leaving the position "open". The
trader concealed his activities by hiding open trading positions, by rolling
open positions forward using off-market, inter-month transactions, and by
providing to counter-parties forged documents that purported to authorize such
transactions. An "inter-month" transaction is one in which the receipt and
delivery of crude oil are scheduled in different months. An "off-market"
transaction is one in which the price is higher or lower than the prices
available in the market on the day of the transaction. By matching one side of
an inter-month transaction with an open position, and using off-market pricing
to match the pricing of the open position, the trader could present
documentation showing both a purchase and a sale, creating the impression of
compliance with our policy. The offsetting side of the inter-month transaction
became a new, hidden open position.
Investigation; Enhancement of Procedures
Upon discovery of the violation and related losses, we engaged an outside law
firm to lead the investigation of the unauthorized trading activities. The law
firm retained specialists from an independent accounting firm to assist in the
investigation. In parallel effort with the investigation mentioned above, the
role of the accounting firm specialists was expanded to include reviewing and
making recommendations for enhancement of our systems, policies and procedures.
As a result, we have developed and adopted a new written policy document and
manual of procedures designed to enhance our processes and procedures and
improve our ability to detect any activity that might occur at an early stage.
See "Terminalling, Storage, Marketing and Gathering Operations--Crude Oil
Volatility; Counter-Cyclical Balance; Risk Management."
To specifically address the methods used by the trader to conceal the
unauthorized trading, in January 2000, we sent a notice to each of our material
counter-parties that no person at Plains All American Pipeline, L.P. was
authorized to enter into off-market transactions. In addition, we have taken the
following actions:
. We have communicated our hedging and trading strategies and risk tolerance to
our traders by more clearly and specifically defining approved strategies and
risk limits in our written procedures.
. The new procedures require (i) more comprehensive and frequent reporting that
will allow our officers to evaluate risk positions in greater detail, and
(ii) enhanced procedures to check compliance with these reporting
requirements and to confirm that trading activity was conducted within
guidelines.
. The procedures provide a system to educate each employee who is involved,
directly or indirectly, in our crude oil transaction activities with respect
to policies and procedures, and impose an obligation to notify the Risk
Manager directly of any questionable transactions or failure of others to
adhere to the policies, practices and procedures.
. Finally, following notification to each of our material counter-parties that
off-market trading is against our policy and that any written evidence to the
contrary is unauthorized and false, the Risk Manager and our other
representatives have also communicated our policies and enhanced procedures
to our counter-parties to advise them of the information we will routinely
require from them to assure timely recording and confirmation of trades.
We can give no assurance that the above steps will serve to detect and prevent
all violations of our trading policy; we believe, however, that such steps
substantially reduce the possibility of a recurrence of unauthorized trading
activities, and that any unauthorized trading that does occur would be detected
before any material loss could develop.
Effects of the Loss
The unauthorized trading and associated losses resulted in a default of
certain covenants under our then-existing credit facilities and significant
short-term cash and letter of credit requirements.
24
In December 1999, we executed amended credit facilities and obtained default
waivers from all of our lenders. We paid approximately $13.7 million to our
lenders in connection with the amended credit facilities. In connection with the
amendments, our former general partner loaned us approximately $114.0 million.
On May 8, 2000, we entered into new bank credit agreements to refinance our
existing bank debt and repay the $114.0 million owed to our former general
partner. The new bank credit agreements also provided us with additional
flexibility for working capital, capital expenditures and other general
corporate purposes. At closing, we had $256.0 million outstanding under a senior
secured revolving credit facility. We also had at closing letters of credit of
approximately $173.8 million and borrowings of approximately $20.3 million
outstanding under a separate senior secured letter of credit and borrowing
facility. We have since refinanced the bank credit facilities we entered into on
May 8, 2000. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources".
In the period immediately following the disclosure of the unauthorized trading
losses, 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. 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.
After the public announcement of the trading losses, class action lawsuits
were filed against us and Plains Resources. Derivative lawsuits have also been
filed in the United States District Court for the Southern District of Texas and
the Delaware Chancery Court, Newcastle County. All of the cases have been
settled or are in the process of being settled. See Item 3. "Legal Proceedings".
ITEM 3. LEGAL PROCEEDINGS
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of our former general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
were filed in the Southern District of Texas, some of which named our former
general partner and Plains Resources as additional defendants. All of the
federal securities claims were consolidated into two actions. The first
consolidated action is that filed by purchasers of Plains Resources' common
stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al.
The second consolidated action is that filed by purchasers of our common units,
and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al.
Plaintiffs alleged that the defendants were liable for securities fraud
violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of
1934 and for making false registration statements under Sections 11 and 15 of
the Securities Act of 1933.
We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
our former general partner and the board of directors of Plains Resources. All
such amounts were reflected in our financial statements at December 31, 2000.
The settlement was approved by the court on December 19, 2001. The order became
final on January 18, 2002. The settlement agreement does not affect the Texas
Derivative Litigation and Delaware Derivative Litigation described below.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named our former general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The court consolidated all
of the cases under the caption In Re Plains All American Inc. Shareholders
Litigation, and has designated the complaint filed in Susser v. Plains All
American Inc. as the complaint in the consolidated action.
The plaintiffs in the Delaware derivative litigation seek, among other things,
to cause the defendants to account for all losses and damages allegedly
sustained by Plains All American from the unauthorized trading losses; to
establish and maintain effective internal controls ensuring that our affiliates
and persons responsible for our affairs do not engage in wrongful practices
detrimental to Plains All American; and to pay for the plaintiffs' costs and
expenses in the litigation, including reasonable attorneys' fees, accountants'
fees and experts' fees.
25
We have reached an agreement in principle with the plaintiffs to settle the
Delaware litigation for approximately $1.1 million. On March 6, 2002, the
Delaware court approved the settlement.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed
in the United States District Court of the Southern District of Texas entitled
Fernandes v. Plains All American Inc., et al, naming our former general partner,
its directors and certain of its officers as defendants. This lawsuit contains
the same claims and seeks the same relief as the Delaware derivative litigation,
described above. We have reached an agreement in principle with the plaintiffs,
subject to approval by the District Court, to settle the Texas litigation for
approximately $112,500.
Other. We, in the ordinary course of business, are a claimant and/or a
defendant in various other legal proceedings. We do not believe that the outcome
of these other legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders, through
solicitation of proxies or otherwise, during the fourth quarter of the fiscal
year covered by this report.
26
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS
The common units, excluding the Class B common units, are listed and traded
on the New York Stock Exchange under the symbol "PAA". On March 15, 2002, the
market price for the common units was $25.61 per unit and there were
approximately 17,300 recordholders and beneficial owners (held in street
name).
The following table sets forth high and low sales prices for the common
units as reported on the New York Stock Exchange Composite Tape, and the cash
distributions paid per common unit for the periods indicated:
COMMON UNIT PRICE RANGE CASH
HIGH LOW DISTRIBUTIONS
-------- -------- -------------
2000
1st Quarter $ 16.56 $ 13.00 $ 0.4500
2nd Quarter 18.63 15.25 0.4625
3rd Quarter 19.75 18.00 0.4625
4th Quarter 20.06 18.00 0.4625
2001
1st Quarter $ 23.59 $ 19.50 $ 0.4750
2nd Quarter 27.86 22.26 0.5000
3rd Quarter 29.50 23.47 0.5125
4th Quarter 27.46 24.76 0.5125
The Class B common units are pari passu with common units with respect to
quarterly distributions, and are convertible into common units upon approval of
a majority of the common unitholders. The Class B unitholders may request that
we call a meeting of common unitholders to consider approval of the conversion
of Class B units into common units. If the approval of a conversion by the
common unitholders is not obtained within 120 days of a request, each Class B
unitholder will be entitled to receive distributions, on a per unit basis, equal
to 110% of the amount of distributions paid on a common unit, with such
distribution right increasing to 115% if such approval is not secured within 90
days after the end of the 120-day period. Except for the vote to approve the
conversion, the Class B units have the same voting rights as the common units.
As of March 15, 2002, there was one Class B unitholder. We have also issued and
outstanding 10,029,619 subordinated units, for which there is no established
public trading market.
Cash Distribution Policy
We distribute on a quarterly basis all of our available cash. Available cash
generally means, for any of our fiscal quarters, all cash on hand at the end of
the quarter less the amount of cash reserves that is necessary or appropriate in
the reasonable discretion of our general partner to:
. provide for the proper conduct of our business;
. comply with applicable law, any of our debt instruments or other
agreements; or
. provide funds for distributions to unitholders and our general partner
for any one or more of the next four quarters.
Minimum quarterly distributions are $0.45 for each full fiscal quarter.
Distributions of available cash to the holders of subordinated units are subject
to the prior rights of the holders of common units to receive the minimum
quarterly distributions for each quarter during the subordination period, and to
receive any arrearages in the distribution of minimum quarterly distributions on
the common units for prior quarters during the subordination period. The
subordination period will end if certain financial tests contained in the
partnership agreement are met for three consecutive four-quarter periods (the
"testing period"), but no sooner than December 31, 2003. During the first
quarter after the end of the subordination period, all of the subordinated units
will convert into Common Units. Early conversion of a portion of the
subordinated units may occur if the testing period is satisfied before
December 31, 2003. We have determined that the first four-quarter period of the
testing period was satisfied as of September 30, 2001. Although we cannot give
assurance in that regard, if we continue to meet the requirements, 25% of the
subordinated units will convert into common units in the fourth quarter of 2003
and the remainder will convert in the first quarter of 2004. Our ability to meet
these requirements is subject to a number of economic and operational
contingencies. See "Management's Discussion and Analysis--Risk Factors Related
to our Business" and "--Forward Looking Statements".
In addition to distributions on its 2% general partner interest, our general
partner is entitled to receive incentive distributions if the amount we
distribute with respect to any quarter exceeds levels specified in our
partnership agreement.
27
Under the quarterly incentive distribution provisions, generally our general
partner is entitled to 15% of amounts we distribute in excess of $0.450 per
unit, 25% of the amounts we distribute in excess of $0.495 per unit and 50% of
amounts we distribute in excess of $0.675 per unit.
Under the terms of our bank credit agreement and letter of credit and
borrowing facility, we are prohibited from declaring or paying any distribution
to unitholders if a default or event of default (as defined in such agreements)
exists. See Item 7. "Management's Discussion and Analysis --Liquidity and
Capital Resources".
28
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
On November 23, 1998, we completed our initial public offering and the
transactions whereby we became the successor to the business of our predecessor
(the midstream subsidiaries of Plains Resources). The historical financial
information below for Plains All American Pipeline was derived from our audited
consolidated financial statements as of December 31, 2001, 2000, 1999 and 1998,
and for the years ended December 31, 2001, 2000 and 1999 and for the period from
November 23, 1998, through December 31, 1998. The financial information below
for our predecessor was derived from the audited combined financial statements
of our predecessor, as of December 31, 1997, and for the period from January 1,
1998, through November 22, 1998, and for the year ended December 31, 1997,
including the notes thereto. The operating data for all periods is derived from
our records as well as those of our predecessor. Commencing April 1, 2001, July
1, 2001, and October 1, 2001, respectively, the results of operations of the
Murphy, CANPET and Wapella acquisitions are included in our results of
operations. Commencing May 1, 1999, the results of operations of the Scurlock
Permian businesses are included in our results of operations. Commencing July
30, 1998, the results of operations of the All American Pipeline and the SJV
Gathering System are included in the results of operations of our predecessor
and Plains All American Pipeline. The selected financial data should be read in
conjunction with the consolidated financial statements, including the notes
thereto, included elsewhere in this report, and Item 7. "Management's Discussion
and Analysis of Financial Condition and Results of Operations".
PREDECESSOR
-------------------------
NOVEMBER 23 TO JANUARY 1 TO YEAR ENDED
YEAR ENDED DECEMBER 31, DECEMBER 31, NOVEMBER 22, DECEMBER 31,
--------------------------------------------- -------------- ----------- -----------
2001 2000 1999 1998 1998 1997
------------ ----------- ------------ -------------- ----------- -----------
(in thousands except per unit data)
STATEMENT OF OPERATIONS DATA:
Revenues $ 6,868,215 $ 6,641,187 $ 10,910,423 $ 398,918 $ 3,118,353 $ 2,815,278
Cost of sales and operations 6,720,970 6,506,504 10,800,109 391,419 3,087,372 2,802,798
Unauthorized trading losses
and related expenses (1) - 6,963 166,440 2,400 4,700 -
Inventory valuation adjustment 4,984 - - - - -
------------ ----------- ------------ -------------- ----------- -----------
Gross margin 142,261 127,720 (56,126) 5,099 26,281 12,480
------------ ----------- ------------ -------------- ----------- -----------
General and administrative
expenses (2) 46,586 40,821 23,211 771 4,526 3,529
Depreciation and amortization 24,307 24,523 17,344 1,192 4,179 1,165
Restructuring expense - - 1,410 - - -
------------ ----------- ------------ -------------- ----------- -----------
Total expenses 70,893 65,344 41,965 1,963 8,705 4,694
------------ ----------- ------------ -------------- ----------- -----------
Operating income (loss) 71,368 62,376 (98,091) 3,136 17,576 7,786
Interest expense (29,082) (28,691) (21,139) (1,371) (11,260) (4,516)
Gain on sale of assets (3) 984 48,188 16,457 - - -
Interest and other income (4) 401 10,776 958 12 572 138
------------ ----------- ------------ -------------- ----------- -----------
Income (loss) before provision
(benefit) in lieu of income
taxes, extraordinary item and
cumulative effect of accounting
change 43,671 92,649 (101,815) 1,777 6,888 3,408
Provision (benefit) in lieu of
income taxes - - - - 2,631 1,268
------------ ----------- ------------ -------------- ----------- -----------
Income (loss) before extraordinary
item and cumulative effect of
accounting change $ 43,671 $ 92,649 $ (101,815) $ 1,777 $ 4,257 $ 2,140
============ =========== ============ ============== =========== ===========
Basic and diluted net income
(loss) per limited partner unit
before extraordinary item and
cumulative effect of accounting
change (5) $ 1.12 $ 2.64 $ (3.16) $ 0.06 $ 0.25 $ 0.12
============ =========== ============ ============== =========== ===========
Weighted average number of
limited partner units outstanding 37,528 34,386 31,633 30,089 17,004 17,004
============ =========== ============ ============== =========== ===========
(table continued on following page)
29
PREDECESSOR
-------------------------
NOVEMBER 23 TO JANUARY 1 TO YEAR ENDED
YEAR ENDED DECEMBER 31, DECEMBER 31, NOVEMBER 22, DECEMBER 31,
--------------------------------------------- -------------- ----------- -----------
2001 2000 1999 1998 1998 1997
------------ ----------- ------------ -------------- ----------- -----------
(in thousands except per unit data)
BALANCE SHEET DATA:
(AT END OF PERIOD):
Working capital (6) $ 52,922 $ 47,111 $ 101,539 $ 2,231 N/A $ 2,017
Total assets 1,261,251 885,801 1,223,037 607,186 N/A 149,619
Related party debt - Long-term - - 114,000 - N/A 28,531
Total debt (7) 456,159 321,300 368,819 184,750 N/A 18,000
Partners' capital 402,797 213,999 192,973 270,543 N/A -
Combined equity - - - - N/A 5,975
OTHER DATA:
Adjusted EBITDA (8) $ 109,595 $ 103,048 $ 89,074 $ 6,740 $ 27,027 $ 9,089
Maintenance capital
expenditures (9) 3,401 1,785 1,741 200 1,508 678
Net cash provided by (used in)
operating activities (10) (29,953) (33,511) (71,245) 7,218 21,384 (12,869)
Net cash provided by (used in)
investing activities (249,491) 211,001 (186,093) (3,089) (399,611) (1,854)
Net cash provided by (used in)
financing activities 279,529 (227,832) 305,603 1,374 386,154 14,321
OPERATING DATA:
Volumes (barrels per day)(11):
All American
Tariff (12) 69,300 73,800 102,700 110,200 113,700 N/A
Margin (13) 60,600 60,000 54,100 50,900 49,100 N/A
Canada 223,300 N/A N/A N/A N/A N/A
Other 124,200 106,500 61,400 - - N/A
------------ ----------- ------------- -------------- ----------- -----------
Total pipeline 477,400 240,300 218,200 161,100 162,800 N/A
============ =========== ============= ============== =========== ===========
Lease gathering (14) 375,300 262,600 264,700 126,200 87,100 71,400
Bulk purchases (15) 54,200 27,700 138,200 133,600 94,700 48,500
------------ ----------- ------------- -------------- ----------- -----------
Total 429,500 290,300 402,900 259,800 181,800 119,900
============ =========== ============= ============== =========== ===========
Terminal throughput (16) 99,000 67,000 83,300 61,900 81,400 76,700
============ =========== ============= ============== =========== ===========
- ------------
(1) In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $174.0
million, including estimated associated costs and legal expenses of which
$166.4 million and $7.1 million was recognized in 1999 and 1998,
respectively. In 2000, we recognized an additional $7.0 million charge for
litigation related to the unauthorized trading losses. See Items 1 and 2.
"Business and Properties -- Unauthorized Trading Losses".
(2) General and administrative expenses for 2001 and 2000 include a $1.0
million charge and a $5.0 million charge, respectively, to reserve
potentially uncollectible accounts receivable. Operating expenses for 2001
also include a similar charge of $2.0 million. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Results of Operations".
(3) In March 2000, we completed the sale of 5.2 million barrels of crude oil
linefill from the All American Pipeline. We recognized gains of $28.1
million and $16.5 million in 2000 and 1999, respectively, in connection
with that sale. We also sold a segment of the All American Pipeline to El
Paso and recognized a gain of $20.1 million in the first quarter of 2000.
See Items 1 and 2. "Business and Properties--Acquisitions and Dispositions
-- All American Pipeline Linefill Sale and Asset Disposition".
(4) For the year ended December 31, 2000, this amount includes $9.7 million of
previously deferred gains from terminated interest rate swaps recognized as
a result of debt extinguishment.
(5) Basic and diluted net income (loss) per unit is computed by dividing the
limited partners' interest in net income by the number of outstanding
common and subordinated units. For periods prior to November 23, 1998, the
number of units are equal to the common and subordinated units received by
our former general partner in exchange for the assets contributed to the
Partnership.
(6) At December 31, 1999, working capital includes $37.9 million of pipeline
linefill and $103.6 million for the segment of the All American Pipeline
that were both sold in the first quarter of 2000. See Items 1 and 2.
"Business and Properties--Acquisitions and Dispositions--All American
Pipeline Linefill Sale and Asset Disposition".
(7) Total debt in 1999 excludes related party debt. Total debt at December 31,
2001, includes an aggregate $100 million of short-term debt outstanding
under our $200 million senior secured letter of credit and borrowing
facility attributable to contango inventory purchases, which was
repaid in January 2002 with proceeds from the sale of the inventory. We
continuously use this facility for short-term borrowings of contango
inventory purchases.
(8) EBITDA means earnings before interest expense, income taxes, depreciation
and amortization. Adjusted EBITDA also excludes unauthorized trading
losses, noncash compensation ($5.7 million, $3.1 million and $1.0 million
in 2001, 2000 and 1999, respectively), restructuring expense, gains on the
sales of assets,
30
allowance for accounts receivable ($3.0 million in 2001 and $5.0 million in
2000), noncash inventory valuation adjustment, the impact on earnings of
noncash SFAS 133 items, gain on early termination of interest rate swaps,
and extraordinary loss from extinguishment of debt. Adjusted EBITDA is not
a measurement presented in accordance with GAAP and is not intended to be
used in lieu of GAAP presentations of results of operations and cash
provided by operating activities. EBITDA is commonly used by debt holders
and financial statement users as a measurement to determine the ability of
an entity to meet its interest obligations.
(9) Maintenance capital expenditures are capital expenditures made to replace
partially or fully depreciated assets to maintain the existing operating
capacity of existing assets or extend their useful lives. Capital
expenditures made to expand our existing capacity, whether through
construction or acquisition, are not considered maintenance capital
expenditures. Repair and maintenance expenditures associated with existing
assets that do not extend the useful life or expand operating capacity are
charged to expense as incurred.
(10) See Item 7. "Management's Discussion and Analysis--Liquidity and Capital
Resources--Cash Flows" and "--Operating Activities" for a discussion of
negative amounts in 2001, 2000 and 1999.
(11) Includes average daily volumes from acquisition effective dates,
extrapolated for the full year in which the acquisitions were consummated.
(12) Represents crude oil deliveries on the All American Pipeline.
(13) Represents crude oil deliveries on the SJV Gathering System.
(14) Represents barrels of crude oil purchased at the wellhead, including
volumes which were purchased under the Marketing Agreement.
(15) Represents barrels of crude oil purchased at collection points, terminals
and pipelines.
(16) Represents total crude oil barrels delivered from the Cushing Terminal and
the Ingleside Terminal.
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion of our financial condition and results of our
operations should be read in conjunction with our historical consolidated
financial statements and accompanying notes. For more detailed information
regarding the basis of presentation for the following financial information, see
the notes to the historical consolidated financial statements.
OVERVIEW
We were formed in September of 1998 to acquire and operate the midstream
crude oil business and assets of Plains Resources Inc. and its wholly owned
subsidiaries. On November 23, 1998, we completed our initial public offering and
the transactions whereby we became the successor to the business of our
predecessor. We are a master limited partnership and conduct our operations
through our wholly owned operating limited partnerships Plains Marketing, L.P.,
All American Pipeline, L.P. and Plains Marketing Canada, L.P.
In May 2001, management and a group of financial investors entered into a
transaction with Plains Resources to acquire control of our general partner and
a majority of the outstanding subordinated units. The transaction closed in June
2001. As a result of this transaction, Plains Resources' ownership in the
general partner was reduced from 100% to 44% and, combined with two equity
offerings conducted in 2001, Plains Resources' overall effective ownership in
the Partnership (which includes its ownership in common and subordinated units)
was reduced from 55% to approximately 29%. See Item 12. "Security Ownership of
Certain Beneficial Owners and Management". In addition, certain officers of the
general partner who previously were also officers of Plains Resources terminated
their affiliation with Plains Resources and as a result now devote 100% of their
efforts to the management of the Partnership. In connection with the General
Partner Transition, certain equity interests previously granted to management
and outside directors vested, resulting in a charge to the Partnership's income
of approximately $6.1 million, of which Plains Resources funded approximately
94%.
We are engaged in interstate and intrastate transportation, marketing and
terminalling and storage of crude oil and marketing of liquefied petroleum gas.
Pipeline Operations. Our activities from pipeline operations generally
consist of transporting third-party volumes of crude oil for a fee, third party
leases of pipeline capacity, barrel exchanges and buy/sell arrangements. We also
utilize our pipelines in our merchant activities conducted under our gathering
and marketing business. Utilization of our pipelines in our gathering and
marketing business provides us with a competitive advantage over third party
gatherers that do not have similarly located pipelines, because generally it
costs less to transport crude oil on pipelines than alternative methods of
transportation. Tariffs and other fees on our pipeline systems vary by receipt
point and delivery point. The gross margin generated by our tariff and other
fee-related activities depends on the volumes transported on the pipeline and
the level of the tariff and other fees charged, as well as the fixed and
variable costs of operating the pipeline. Gross margin from our pipeline
capacity leases, barrel exchanges and buy/sell arrangements generally reflect a
negotiated amount.
Terminalling and Storage Activities and Gathering and Marketing Activities.
Terminals are facilities where crude oil is transferred to or from storage or a
transportation system, such as a pipeline, to another transportation system,
such as trucks or another pipeline. The operation of these facilities is called
"terminalling". Gross margin from terminalling and storage activities is
dependent on the throughput volumes, the volume of crude oil stored and the
level of fees generated from our terminalling and storage services. Gross margin
from our gathering and marketing activities is dependent on our ability to sell
crude oil at a price in excess of our aggregate cost. These operations are
margin businesses, and 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 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, the market is backward,
meaning that the price of crude oil for future deliveries is lower than current
prices. A backward 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. 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.
We establish a margin 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.
32
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. We purchase crude oil on both a fixed and floating price basis. As
fixed price barrels are purchased, we enter into sales arrangements with
refiners, trade partners or on the NYMEX, which establishes a margin and
protects it against future price fluctuations. When floating price barrels are
purchased, we match those contracts with similar type sales agreements with our
customers, or likewise establish a hedge position using the NYMEX futures
market. From time to time, we enter into arrangements that expose us to basis
risk. Basis risk occurs when crude oil is purchased based on a crude oil
specification and location that differs from the countervailing sales
arrangement. In order to lock in profits involving our physical assets and to
manage risks associated with our crude purchase obligations, we use derivative
instruments. Except for pre-defined inventory positions as discussed below, 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. See Items 1 and 2., "Business and
Properties--Crude Oil Volatility; Counter-Cyclical Balance; Risk
Management". In November 1999, we discovered that this policy was violated. See
Items 1 and 2. "Business and Properties--Unauthorized Trading Losses" and
"Unauthorized Trading Losses" below. 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.
2001 ACQUISITIONS
We completed a number of acquisitions in 2001 that impacted the results of
operations discussed in this section. We continue to have an active acquisition
program and have completed two acquisitions in 2002 as of March 15. See Items 1
and 2. "Business and Properties--Acquisitions and Dispositions".
Wapella Pipeline System
In December 2001, we consummated the acquisition of the Wapella Pipeline
System from private investors for approximately $12.0 million, including
transaction costs. The system is 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 acquisition also includes approximately 21,500 barrels of
crude oil storage capacity located along the system as well as a truck terminal.
The Wapella acquisition was accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 141. The purchase price allocation
is as follows (in thousands):
Crude oil pipeline, gathering and
terminal assets $ 10,251
Other property and equipment 1,720
---------
Total $ 11,971
=========
CANPET Energy Group Inc.
In July 2001, we acquired the assets of CANPET Energy Group Inc. ("CANPET"),
a Calgary-based Canadian crude oil and liquefied petroleum gas marketing
company, for approximately $42.0 million plus excess inventory at the closing
date of approximately $25.0 million. Approximately $24.0 million of the purchase
price plus $25 million for the additional inventory was paid in cash at closing,
and the remainder, which is subject to certain performance standards, will be
paid in common units in April 2004, if such standards are met. At the time of
the acquisition, CANPET's activities consisted of gathering approximately 75,000
barrels per day of crude oil and marketing an average of approximately 26,000
barrels per day of natural gas liquids. 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.
33
The CANPET acquisition was accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with SFAS 141. The
purchase price allocation (including transaction costs) is as follows (in
thousands):
Inventory $29,708
Goodwill 8,818
Intangible assets (contracts) 980
Other assets, including debt issue costs 1,661
Pipeline linefill 4,332
Crude oil gathering and terminal
assets 4,243
Other property and equipment 502
-------
Total $50,244
=======
Murphy Oil Company Ltd. Midstream Operations
In May 2001, we acquired 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. Initial financing for the acquisition was provided through borrowings
under our bank credit facilities. The purchase included $6.5 million for excess
inventory in the pipeline 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 through that system in
May of 2001.
Murphy agreed to continue to transport production from fields previously
delivering crude oil to these pipeline systems, under a long-term contract. At
the time of acquisition, these volumes averaged approximately 11,000 barrels per
day. Total volumes transported on the pipeline system in 2001 were approximately
223,000 barrels per day of light, medium and heavy crudes, as well as
condensate.
The Murphy acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with APB 16. The
purchase price allocation, as adjusted pursuant to the provisions of the
purchase and sale agreement upon resolution of an outstanding pipeline tariff
dispute, is as follows (in thousands):
Crude oil pipeline, gathering and terminal
assets $145,106
Pipeline linefill 7,602
Net working capital items 1,953
Other property and equipment 487
Other assets, including debt issue costs 360
--------
Total $155,508
========
UNAUTHORIZED TRADING LOSSES
In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $174.0
million, which includes estimated associated costs and legal expenses.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses. See
Items 1 and 2. "Business and Properties--Unauthorized Trading Losses" for a
discussion of the unauthorized trading loss, its financial effects and the steps
taken to prevent future violations of our trading policies. See also Item 3.
"Legal Proceedings".
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets and liabilities, as
well as the disclosure of contingent assets and liabilities, at the date of the
financial statements. Such estimates and assumptions also affect the reported
amounts of revenues and expenses during the reporting period. Although we
believe these estimates are reasonable, actual results could differ from these
estimates. The critical accounting policies that we have identified are
discussed below.
34
Depreciation and Amortization
We calculate our depreciation and amortization based on estimated useful
lives and salvage values of our assets. When assets are put into service, we
make estimates with respect to useful lives that we believe are reasonable.
However, subsequent events could cause us to change our estimates, thus
impacting the future calculation of depreciation and amortization. In
conjunction with the recent adoption of SFAS 141, we are required to determine
the portion of goodwill or intangibles, relating to acquisitions after June 30,
2001, which have finite lives as opposed to indefinite lives. Intangibles with
indefinite lives are not amortized but instead are periodically assessed for
impairment. The impairment testing entails estimating future net cash flows
relating to the asset, based on management's estimate of market conditions
including pricing, demand, competition, operating costs and other factors.
Intangibles with finite lives are amortized over the estimated useful life
determined by management. Determining the amount of intangibles associated with
an acquisition that relates to such items as relationships, contracts, and
industry expertise involves professional judgment and is ultimately based on
acquisition models and management's assessment of the value of the assets
acquired.
Allowance for Doubtful Accounts Receivable
We routinely review our receivable balances to identify past due amounts and
analyze the reasons such amounts have not been collected. In many instances,
such uncollected amounts involve billing delays and discrepancies or disputes as
to the appropriate price, volumes or quality of crude oil delivered, received or
exchanged. We also attempt to monitor changes in the creditworthiness of our
customers as a result of developments related to each customer, the industry as
a whole and the general economy. Based on these analyses, we have established
an allowance for doubtful accounts receivable and consider the reserve adequate.
Revenue and Expense Accruals
We routinely make accruals for both revenues and expenses due to the timing
of compiling billing information, receiving third party information and
reconciling our records with those of third parties. The delayed information
includes, among other things, actual volumes of crude oil purchased, transported
or sold, claims for employee medical insurance, and invoices for purchases and
other operating expenses. In situations where we are required to make mark to
market estimates pursuant to SFAS 133, the estimates of gains or losses at a
particular period end do not reflect the end results of particular transactions,
and will most likely not reflect the actual gain or loss at the conclusion of a
transaction. We make accruals to reflect estimates for these items based on our
internal records and information from third parties. We believe our estimates
for these items are reasonable, but there is no assurance that actual amounts
will not vary significantly from estimated amounts.
Liability and Contingency Accruals
We accrue reserves for contingent liabilities including, but not limited to,
environmental remediation and potential legal claims. Accruals are made when
our assessment indicates that it is probable that a liability has occurred and
the amount of liability can be reasonably estimated. Our estimates are based on
all known facts at the time and our assessment of the ultimate outcome. These
estimates can be increased or decreased as additional information is obtained or
resolution is achieved.
RESULTS OF OPERATIONS
Analysis of Three Years Ended December 31, 2001
Commencing April 1, July 1, and October 1, 2001, respectively, the results
of operations of the Murphy, CANPET and Wapella acquisitions are included in our
results of operations. The results of operations for the year ended December 31,
1999, include the results of the Scurlock acquisition effective May 1, 1999, and
the West Texas Gathering System acquisition effective July 1, 1999.
For 2001, we reported net income of $44.2 million on total revenue of $6.9
billion compared to net income for 2000 of $77.5 million on total revenue of
$6.6 billion and a net loss for 1999 of $103.4 million on total revenue of $10.9
billion. Such results include the impacts of unusual, non-recurring or
extraordinary items as follows:
2001
. a $6.1 million charge associated with the vesting of phantom
partnership units primarily as a result of the General Partner
Transition in June 2001. See Item 13. "Certain Relationships and
Related Transactions--Transactions with Related Parties--Transactions
Grant Agreements." The vesting had no effect on the number of units
outstanding, as the units were satisfied out of units owned by Plains
35
Resources. Approximately $5.7 million of the charge (included in
general and administrative expenses) was noncash. This portion of the
charge had no impact on equity as it was offset by a deemed capital
contribution by our former general partner;
. a $5.0 million noncash writedown of operating crude oil inventory in
the fourth quarter of 2001 to reflect prices at December 31, 2001.
During 2001, the price of crude oil traded on the NYMEX averaged
$25.98 per barrel. At December 31, 2001, the NYMEX crude oil price was
approximately 24% lower, or $19.84 per barrel. The Partnership uses
the average cost method for recording inventory and the noncash
writedown reflects the impact of a lower of cost or market valuation;
. a $3.0 million reserve for potentially uncollectible accounts
receivable; and
. a $1.0 million gain on the sale of excess communications equipment.
2000
. a $28.1 million gain on the sale of crude oil linefill;
. a $20.1 million gain on the sale of the segment of the All American
Pipeline that extends from Emidio, California, to McCamey, Texas;
. $9.7 million of previously deferred gains on interest rate swap
terminations recognized due to the early extinguishment of debt;
. an extraordinary loss of $15.1 million related to the early
extinguishment of debt;
. a $7.0 million charge for litigation related to the unauthorized
trading losses;
. a $5.0 million reserve for potentially uncollectible accounts
receivable;
. amortization of $4.6 million of debt issue costs associated with
facilities put in place during the fourth quarter of 1999 subsequent
to the unauthorized trading loss; and
. $3.1 million of noncash compensation expense, attributable to the
vesting of rights to receive phantom partnership units granted by an
affiliate of Plains Resources. See Item 13. "Certain Relationships and
Related Transactions--Transactions with Related Parties--Transaction
Grant Agreements."
1999
. $166.4 million of unauthorized trading losses;
. a $16.5 million gain on the sale of crude oil linefill that was sold
in 1999;
. restructuring expense of $1.4 million;
. an extraordinary loss of $1.5 million related to the early
extinguishment of debt; and
. $1.0 million of noncash compensation expense attributable to the
vesting of phantom partnership units as described for 2000 and 2001
above.
Excluding the items listed above, we would have reported net income of $57.3
million, $54.4 million and $50.6 million for the years ended December 31, 2001,
2000 and 1999, respectively.
36
The following table sets forth financial and operating information for the
periods presented and includes the impact of the items discussed above (in
thousands):
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2001 2000 1999
---------- ---------- -----------
OPERATING RESULTS:
Revenues $6,868,215 $6,641,187 $10,910,423
========== ========== ===========
Gross margin
Pipeline $ 71,322 $ 51,787 $ 58,001
Terminalling and storage
and gathering and marketing 75,923 82,896 52,313
Unauthorized trading losses - (6,963) (166,440)
Inventory valuation adjustment (4,984) - -
---------- ---------- -----------
Total 142,261 127,720 (56,126)
General and administrative expense (46,586) (40,821) (23,211)
---------- ---------- -----------
Gross profit $ 95,675 $ 86,899 $ (79,337)
========== ========== ===========
Extraordinary item and cumulative
effect of accounting change $ 508 $ (15,147) $ (1,545)
========== ========== ===========
Net income (loss) $ 44,179 $ 77,502 $ (103,360)
========== ========== ===========
AVERAGE DAILY VOLUMES (BARRELS PER DAY)(1):
Pipeline Activities:
All American
Tariff and fee activities 69 74 103
Margin activities 61 60 54
Canada 223 - -
Other 124 107 61
---------- ---------- -----------
Total 477 241 218
========== ========== ===========
Lease gathering 375 262 265
Bulk purchases 54 28 138
---------- ---------- -----------
Total 429 290 403
========== ========== ===========
Terminal throughput 99 67 83
========== ========== ===========
Storage leased to third parties,
monthly average volumes 2,356 1,657 1,975
========== ========== ===========
(1) Includes average daily volumes from acquisition effective dates,
extrapolated for the full year in which acquisitions were consummated.
Revenues. Total revenues were $6.9 billion, $6.6 billion and $10.9 billion
for 2001, 2000 and 1999, respectively. The small increase in 2001 as compared to
2000 was primarily due to the impact of our Canadian acquisitions offset by
lower oil prices. The decrease in 2000 as compared to 1999 was primarily
attributable to lower bulk purchases and exchange volumes associated with our
gathering and marketing activities, partially offset by higher crude oil prices.
We significantly reduced the volume of our bulk purchases after our unauthorized
trading losses in 1999, because these transactions typically have lower margins,
and sellers of the crude oil were requesting letters of credit, which increased
our costs on these transactions.
Cost of Sales and Operations. Cost of sales and operations was $6.7 billion,
$6.5 billion and $10.8 billion in 2001, 2000 and 1999, respectively. Year-to-
year changes were primarily due to the reasons discussed above for revenues.
Inventory Valuation Adjustment. We recorded a noncash charge of $5.0 million
related to inventory valuation for the year ended December 31, 2001. We utilize
an average cost method of valuing our operating inventory. This charge was
required due to the drop in crude oil prices during 2001.
Unauthorized Trading Losses. We recognized losses of approximately $7.0
million and $166.4 million in 2000 and 1999, respectively, as a result of
unauthorized trading by a former employee. See "--Unauthorized Trading Losses".
General and Administrative. General and administrative expenses were $46.6
million for the year ended December 31, 2001, an increase of approximately 14%,
or $5.8 million as compared to $40.8 million in 2000. G&A expenses were $23.2
million in 1999. The overall increase from 2000 to 2001 is primarily due to (1)
a $4.7 million increase associated with the Canadian acquisitions, (2) a $2.6
million increase in noncash compensation expense, (3) a $.8 million increase in
personnel related expenses, primarily associated with increased insurance costs
and additional personnel costs associated with the General Partner Transition
and (4) a $4 million decrease to G&A resulting from a reduction year over year
in charges to reserve for potentially uncollectible receivables. The overall
increase from 1999 to 2000 is primarily attributable to (1) a $5.7 million
increase associated with the Scurlock acquisition in mid-1999, (2) a $5.0
million charge to expense associated with
37
potentially uncollectible accounts receivable, (3) approximately $4.6 million of
consulting and accounting charges related to the unauthorized trading loss
investigation, system modifications and enhancements and implementation of SFAS
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
and (4) a $2.1 million increase in noncash compensation expense.
During 2001, 2000 and 1999, we incurred charges of $6.1 million, $3.1
million and $1.0 million, respectively, related to incentive compensation paid
to certain officers and key employees of Plains Resources and its affiliates.
The incentive compensation charges were noncash except for approximately
$400,000 in 2001. In 1998 and 2000, Plains Resources granted certain officers
and key employees the right to earn ownership in our common units owned by it.
These rights provided for a three-year vesting period, subject to distributions
being paid on the common and subordinated units. As a result of the change
control of the general partner interest, all remaining units vested. See Item
13. "Certain Relationships and Related Transactions--Transactions with Related
Parties--Transaction Grant Agreements."
Depreciation and Amortization. Depreciation and amortization expense was
$24.3 million in 2001, $24.5 million in 2000 and $17.3 million in 1999.
Excluding the nonrecurring items discussed below, depreciation and amortization
expense increased approximately $4.9 million in 2001 as compared to 2000
primarily as a result of our Canadian acquisitions. Approximately $5.1 million
of the increase in 2000 as compared to 1999 is primarily related to nonrecurring
amortization of debt issue costs associated with credit facilities put in place
during the fourth quarter of 1999, subsequent to the unauthorized trading
losses. The remaining increase is attributable to the Scurlock and West Texas
Gathering System acquisitions, which were effective May 1, 1999, and July 1,
1999, respectively, as well as our 1999 and 2000 capital additions.
Restructuring Expense. We incurred a $1.4 million restructuring charge in
1999, primarily associated with severance-related expenses of 24 employees who
were terminated. As of December 31, 1999, all severance costs were paid and the
terminated employees were not employed by us.
Interest Expense. Interest expense was $29.1 million in 2001, $28.7 million
in 2000 and $21.1 million in 1999. The decrease in 2001 interest expense is
attributable to lower interest rates, as our average debt balance in 2001 was
slightly higher than in 2000. The increase in 2000 over 1999 is primarily due to
higher interest rates as well as slightly higher average debt balances. During
2001, we capitalized approximately $0.2 million of interest related to capital
projects in the construction phase.
Gain on Sale of Assets. In March 2000, we sold to a unit of 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., had been 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.
Early Extinguishment of Debt. During 2000, we recognized extraordinary
losses, consisting primarily of unamortized debt issue costs, totaling $15.1
million related to the permanent reduction of the All American Pipeline, L.P.
term loan facility and the refinancing of our credit facilities. In addition,
interest and other income for the year ended December 31, 2000, includes $9.7
million of previously deferred gains from terminated interest rate swaps as a
result of debt extinguishment. The extraordinary item of $1.5 million in 1999
relates to the write-off of certain debt issue costs and penalties associated
with the prepayment of debt.
Segment Results
Pipeline Operations. Gross margin from pipeline operations was $71.3 million
for the year ended December 31, 2001, an increase of approximately 38% compared
to $51.8 million for 2000 and $58.0 million for 1999. The increase in 2001
compared to 2000 is primarily attributable to the impact of the Murphy
acquisition. Excluding the Murphy acquisition, gross margin from pipeline
operations would have increased approximately 8%, due to slightly higher volumes
and tariffs, while maintaining operating expenses at a fairly constant level.
Gross margin from pipeline operations was negatively impacted on a comparative
basis in 2000 compared to 1999 due to the sale of the California to West Texas
portion of the All American Pipeline, decreased tariff volumes from California
OCS production and slightly higher fuel and power charges in 2000. These
decreases in 2000 were partially offset by increased margins from the Scurlock
and West Texas gathering system acquisitions in mid-1999.
38
The margin between revenue and direct cost of crude purchased from our
pipeline margin activities was $14.8 million for the year ended December 31,
2001, compared to $21.1 million and $35.6 million for 2000 and 1999,
respectively. Pipeline tariff and fee revenues were approximately $52.9 million
for the year ended December 31, 2001, compared to approximately $47.0 million
for 2000 and approximately $46.4 million for 1999. Pipeline operations and
maintenance expenses were approximately $19.0 million, $16.3 million and $24.0
million for the years ended December 31, 2001, 2000 and 1999, respectively.
Average daily pipeline volumes totaled 477,000 barrels per day, 241,000
barrels per day and 218,000 barrels per day in 2001, 2000 and 1999,
respectively. Approximately 223,000 barrels per day in 2001 are attributable to
the Murphy acquisition. Average daily volumes from the Murphy acquisition are
included from the effective date of the acquisition, April 1, 2001, extrapolated
for the full year. Volumes on the All American Pipeline decreased from an
average of 134,000 barrels per day in 2000 to 110,000 barrels per day in 2001
due to the reasons discussed above. All American's tariffs volumes attributable
to California OCS production were approximately 69,000 barrels per day in 2001
compared to 74,000 barrels per day in 2000. Volumes from the Santa Ynez and
Point Arguello fields, both offshore California, have steadily declined from
1995 through 2001. 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, based on the 2001 average tariff rate. Effective
January 1, 2002, the average tariff increased an average of approximately 11% on
the All American Pipeline. Tariff volumes shipped on the Scurlock and West Texas
gathering systems averaged 124,000 barrels per day and 107,000 barrels per day
in 2001 and 2000, respectively. The 1999 period includes average daily volumes
for Scurlock effective May 1, 1999, and West Texas gathering system average
daily volumes effective July 1, 1999, in each case extrapolated for the full
year.
Gathering and Marketing Activities and Terminalling and Storage Activities.
Gross margin from gathering and marketing and terminalling and storage
activities was approximately $75.9 million for the year ended December 31, 2001,
(excluding the $5.0 inventory valuation charge) reflecting a 8% decrease over
the $82.9 million reported for 2000 and a 45% increase over the $52.3 million
reported for 1999. Gross margin for 2000 and 1999 exclude the unauthorized
trading losses. The decrease in margin in 2001 is primarily attributable to a
relatively weak environment for gathering and marketing due to market
conditions. The market conditions during 2000 were favorable for gathering and
marketing margins. The increase in gross margin from 1999 to 2000 is primarily
due to a full year of results from the Scurlock acquisition and increased per
barrel margins due to the strong crude oil market in 2000. Gross revenues from
gathering, marketing, terminalling and storage activities were approximately
$6.5 billion, $6.1 billion and $10.1 billion for the years ended December 31,
2001, 2000 and 1999, respectively.
Lease gathering volumes averaged 375,000 barrels per day in 2001, 262,000
barrels per day in 2000 and 265,000 barrels per day in 1999. Bulk purchase
volumes averaged 54,000 barrels per day, 28,000 barrels per day and 138,000
barrels per day in 2001, 2000 and 1999, respectively. The increases in 2001 are
primarily due to the average daily volumes attributable to our Canadian
acquisitions from their effective dates, extrapolated for the full year. The
decreases in 2000 compared to 1999 are due primarily to a significant amount of
low margin barrels that were phased out after the discovery of the trading
losses, partially offset by increased volumes attributable to the Scurlock
acquisition, which was effective May 1, 1999.
In the period immediately following the disclosure of the unauthorized
trading losses, 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 to us of
obtaining letters of credit increased under our credit facility. In many
instances we arranged for letters of credit to secure our obligations to
purchase crude oil from our customers, which increased our letter of credit
costs and decreased our unit margins. In other instances, primarily involving
lower margin wellhead and bulk purchases, our purchase contracts were
terminated. We estimate that adjusted EBITDA and net income was adversely
affected by approximately $6.0 million in 2000 as a result of the increase in
letter of credit costs and reduced volumes. Currently, our letter of credit
requirement levels are lower than those levels existing prior to the
unauthorized trading losses. Our senior implied credit ratings from Standard and
Poor's and Moody's prior to the unauthorized trading loss were BB and Ba3,
respectively. As of March 1, 2002, our ratings from these respective agencies
were BB+ and Ba2.
Terminal throughput, which includes both our Cushing and Ingleside
terminals, was 99,000, 67,000 and 83,000 barrels per day for the years ended
December 31, 2001, 2000 and 1999, respectively. Storage leased to third parties
averaged 2.4 million, 1.8 million and 2.0 million barrels per month for the same
periods.
LIQUIDITY AND CAPITAL RESOURCES
Cushing Terminal Expansion
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
39
be completed in late 2002 or early 2003. The two expansion projects are expected
to cost, in the aggregate, approximately $22 million and will expand the total
capacity of the facility by 71% to approximately 5.3 million barrels. We expect
to fund the cost of the expansions from cash generated by operations, working
capital and our revolving credit facility.
General
Cash generated from operations and our credit facilities are our primary
sources of liquidity. At December 31, 2001, we had working capital of
approximately $52.9 million and approximately $425 million of availability under
our revolving credit facility.
We believe that we have sufficient liquid assets, cash from operations and
borrowing capacity under our credit agreements to meet our financial
commitments, debt service obligations, contingencies and anticipated capital
expenditures. However, we are subject to business and operational risks that
could adversely effect our cash flow. A material decrease in our cash flows
would likely produce a corollary adverse effect on our borrowing capacity. See
"--Risk Factors".
Cash Flows
YEAR ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
------- ------- -------
(IN MILLIONS)
Cash provided by (used in):
Operating activities $ (30.0) $ (33.5) $ (71.2)
Investing activities (249.5) 211.0 (186.1)
Financing activities 279.5 (227.8) 305.6
Operating Activities. Net cash used in operating activities in 2001 is
primarily attributable to inventory purchased and stored in our facilities, for
sale and delivery at a later date. Excluding these inventory purchases, cash
provided by operating activities was approximately $88.0 million in 2001. Except
for minor amounts, the inventory has been hedged against future price risk by
using NYMEX transactions and fixed price sales contracts. Net cash used in
operating activities in 2000 and 1999 resulted primarily from the unauthorized
trading losses. The losses were partially offset by increased margins due to the
Scurlock and West Texas Gathering System acquisitions.
Investing Activities. Net cash used in investing activities in 2001 included
$229 million for the acquisitions described above and $21.1 million primarily
for other expansion and acquisition projects. Net cash provided by investing
activities for 2000 included approximately $224.0 million of proceeds from the
sale of the All American Pipeline and pipeline linefill offset by approximately
$12.6 million of capital expenditures. Capital expenditures for 2000 included
approximately $10.8 million for expansion capital and $1.8 million for
maintenance capital. Net cash used in investing activities for 1999 included
approximately $176.9 million for acquisitions, primarily for the Scurlock and
West Texas gathering system acquisitions, $11.1 million for expansion capital
and $1.7 million for maintenance capital.
Financing activities. Cash provided by financing activities in 2001
consisted primarily of (1) $134.3 million in short-term and long-term debt, (2)
$227.5 million for equity issued, (3) the payment of $75.9 million in
distributions to unitholders and (4) the payment of $6.4 million in financing
costs.
Cash used in financing activities in 2000 consisted primarily of (1) net
payments of $47.5 million of short-term and long-term debt, (2) the repayment of
subordinated debt of $114.0 million to our former general partner and (3)
distributions to unitholders of $59.6 million. Proceeds used to reduce the bank
debt primarily came from the asset sales discussed above. Proceeds to repay the
$114.0 million of subordinated debt to our former general partner came from our
revolving credit facility, which was refinanced in May 2000. Cash provided by
financing activities in 1999 was generated from net issuances of (1) $76.5
million in common and Class B units, (2) $184.1 million of short-term and long-
term debt and (3) $114.0 million of subordinated debt to our former general
partner. Financing activities for 1999 includes $51.7 million in distributions
to unitholders.
Capital Expenditures
We have made and will continue to make capital expenditures for acquisitions
and expansion and maintenance capital. Historically, we have financed these
expenditures primarily with cash generated by operations, bank borrowings and
the sale of additional common units. We estimate aggregate capital expenditures
for 2002 (excluding acquisitions) to be approximately $29.6 million, of which
approximately $17.6 million is attributable to the expansion of our Cushing
Terminal noted above and approximately $5.0 million is attributable to
maintenance capital expenditures. We believe that we will have sufficient cash
from working capital, cash flow from operating activities and availability under
our revolving credit facility
40
under our bank credit agreement to fund these expenditures. In addition, the
Partnership has spent approximately $16.2 million for acquisitions as of March
15, 2002 (including $2.5 million paid in the form of a deposit as of December
31, 2001).
Universal Shelf
We have filed with the Securities and Exchange Commission a universal shelf
registration statement that, subject to effectiveness at the time of use, allows
us to issue from time to time up to $700 million of debt or equity securities.
In October 2001, we sold approximately $130 million of common units under the
shelf. Accordingly, as of March 15, 2002, we have the ability to issue
approximately $570 million additional debt or equity securities under this
registration statement.
Commitments
The following table reflects our long-term non-cancelable contractual
obligations as of December 31, 2001 (in millions):
CONTRACTUAL OBLIGATIONS 2002 2003 2004 2005 2006 THEREAFTER TOTAL
- ---------------------------------- ------- ------ ------- ------ ------- ---------- ---------
Long-term debt (including
current maturities) $ 3.0 $ 9.0 $ 10.0 $ 64.7 $ 78.0 $ 190.0 $ 354.7
Operating leases 6.8 6.2 6.3 6.2 4.5 5.6 35.6
Total contractual cash obligations $ 9.8 $ 15.2 $ 16.3 $ 70.9 $ 82.5 $ 195.6 $ 390.3
Operating leases are primarily for office rent and trucks. Other than the
amounts reflected above for these operating leases we have no cash commitments
that are not reflected on the consolidated balance sheet. As is common within
the industry, we have entered into various operational commitments and
agreements related to pipeline operations and to the marketing, transportation,
terminalling and storage of crude oil. It is management's belief that such
commitments will be met without a material adverse effect on our financial
position, results of operations or cash flows.
We will distribute 100% of our available cash within 45 days after the end
of each quarter to unitholders of record, and to our general partner. Available
cash is generally defined as all cash and cash equivalents on hand at the end of
the quarter less reserves established for future requirements. Minimum quarterly
distributions are $0.45 for each full fiscal quarter. Distributions of available
cash to the holders of subordinated units are subject to the prior rights of the
holders of common units to receive the minimum quarterly distributions for each
quarter during the subordination period, and to receive any arrearages in the
distribution of minimum quarterly distributions on the common units for prior
quarters during the subordination period. There were no arrearages on common
units at December 31, 2001. On February 14, 2002, we paid a cash distribution of
$0.5125 per unit on all outstanding units. The total distribution paid was
approximately $23.2 million, with approximately $17.0 million paid to our common
unitholders, $5.1 million paid to our subordinated unitholders and $1.0 million
paid to the general partner for its general partner and incentive distribution
interests.
Our general partner is entitled to incentive distributions if the amount we
distribute with respect to any quarter exceeds levels specified in our
partnership agreement. Under the quarterly incentive distribution provisions,
our general partner is entitled to 15% of amounts we distribute in excess of
$0.450 per common unit, 25% of amounts we distribute in excess of $0.495 per
common unit and 50% of amounts we distribute in excess of $0.675 per common
unit.
In connection with our crude oil marketing activities, we provide certain
purchasers and transporters with irrevocable standby letters of credit to secure
our obligation for the purchase of crude oil. Our liabilities with respect to
these purchase obligations are recorded in accounts payable on our balance sheet
in the month the crude oil is purchased. Generally, these letters of credit are
issued for up to seventy-day periods and are terminated upon completion of each
transaction. At December 31, 2001, we had outstanding letters of credit of
approximately $31.0 million. Such letters of credit are secured by our crude oil
inventory and accounts receivable.
Credit Agreements
In September 2001 we amended and expanded our credit facilities to include a
six-year, $200 million term B loan. In connection with this amendment, we
reduced the revolving portion of the facilities by $50 million. Our credit
facilities currently consist of:
. a $780.0 million senior secured revolving credit and term loan
facility, which is secured by substantially all of our assets. The
facility consists of (i) a $450.0 million domestic revolving facility
(reflecting the $50 million reduction in such facility in connection
with the September amendment), with a $10.0 million letter of credit
sublimit, (ii) a $30.0 million Canadian revolving facility (with a
$5.0 million letter of credit sublimit), (iii) a $100.0 million term
loan and (iv) a $200.0 million term B loan. The facility matures, (i)
as to the aggregate $480.0 million domestic and Canadian revolver
portions, in April 2005, (ii) as to the $100.0 million term portion,
in May 2006, and, (iii) as to the
41
$200.0 million term B loan portion, September 2007. On the revolver
portions, no principal is scheduled for payment prior to maturity. The
$100.0 million term loan portion of this facility has four scheduled
annual payments of principal, commencing May 4, 2002, in the
respective amounts of 1%, 7%, 8% and 8% of the original term principal
amount, with the remaining principal balance scheduled for payment on
the stated maturity date of May 5, 2006. If any part of the term
portion is prepaid prior to its first anniversary, a 1% premium will
be due on that portion. The $200.0 million term B loan has 1% payable
yearly commencing on September 21, 2002, with the remaining principal
balance scheduled for payment on the stated maturity date of September
26, 2007. The term B loan may be prepaid without penalty. The
revolving credit and term loan facility bears interest at our option
at either the base rate, as defined, plus an applicable margin, or
LIBOR plus an applicable margin, and further, the Canadian revolver
may effectively bear interest based upon bankers' acceptance rates. We
incur a commitment fee on the unused portion of the revolver portion
of this credit facility.
. a $200.0 million senior secured letter of credit and borrowing
facility, the purpose of which is to provide standby letters of credit
to support the purchase and exchange of crude oil and other specified
petroleum products for resale and borrowings to finance crude oil
inventory and other specified petroleum products that have been hedged
against future price risk. The letter of credit facility is secured by
substantially all of our assets and has a sublimit for cash borrowings
of $100.0 million to purchase crude oil and other petroleum products
that have been hedged against future price risk and to fund margin
requirements under NYMEX contracts used to facilitate our hedging
activities. The letter of credit facility expires in April, 2004.
Aggregate availability under the letter of credit facility for direct
borrowings and letters of credit is limited to a borrowing base that
is determined monthly based on certain of our current assets and
current liabilities, primarily inventory and accounts receivable and
accounts payable related to the purchase and sale of crude oil and
other specified petroleum products. We incur a commitment fee on the
unused portion of this facility.
Our credit facilities prohibit distributions on, or purchases or redemptions
of, units if any default or event of default is continuing. In addition, the
agreements contain various covenants limiting our ability to, among other
things:
. incur indebtedness;
. grant liens;
. sell assets;
. make investments;
. engage in transactions with affiliates;
. enter into certain contracts; and
. enter into a merger or consolidation.
Our credit facilities treat a change of control as an event of default and
also require us to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio which is not greater than 4.00 to 1.0;
. an interest coverage ratio which is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.70 to 1.0 prior to
December 31, 2002, and 0.65 to 1.0 thereafter.
A default under our credit facilities would permit the lenders to accelerate
the maturity of the outstanding debt and to foreclose on the assets securing the
credit facilities. As long as we are in compliance with our commercial credit
agreements, they do not restrict our ability to make distributions of "available
cash" as defined in our partnership agreement. We are currently in compliance
with the covenants contained in our credit agreements.
The credit facilities provide that the Partnership may issue up to $400.0
million of senior unsecured debt that has a maturity date extending beyond the
maturity date of the credit facilities. If senior unsecured debt is issued, the
aggregate amount available under the $450.0 million U.S. revolving credit
facility will be reduced by an amount equal to (A) 40% of the face amount of the
senior unsecured debt if the aggregate amount of new debt issued is less than
$350.0 million, or (B) 50% of the face amount of the senior unsecured debt if
the aggregate amount of new debt issued is equal to or greater than $350.0
million; provided, however, in both cases, the amount of the revolver reduction
is decreased by $50.0 million.
In January 2002, we amended our credit facility to provide the Partnership
with greater structuring flexibility to finance larger acquisitions by amending
the limitation and restrictions on asset sales, including the removal of a
provision that required lender approval before making any acquisition greater
than $50.0 million.
42
Contingencies
Following our announcement in November 1999 of our losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits were
filed against us, certain of our former general partner's officers and directors
and in some of these cases, our former general partner and Plains Resources Inc.
alleging violations of the federal securities laws. In addition, derivative
lawsuits were filed in the Delaware Chancery Court against our former general
partner, its directors and certain of its officers alleging the defendants
breached the fiduciary duties owed to us and our unitholders by failing to
monitor properly the activities of our traders. We have settled or reached
agreement in principle to settle all of these suits. See Item 3. "--Legal
Proceedings".
We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover releases that were previously
unidentified. Although 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.
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 September 11 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.
OUTLOOK
As is common with most merchant activities, our ability to generate a profit
on our margin activities is not tied to the absolute level of crude oil prices
but is generated by the difference between the price paid and other costs
incurred in the purchase of crude oil versus the price at which we sell crude
oil. The gross margin generated by tariff and other fee activities depends on
the volumes transported on the pipeline and the level of the tariff or fee
charged, as well as the fixed and variable costs of operating the pipeline.
These operations are affected by overall levels of supply and demand for crude
oil.
Our operations have been impacted by higher fuel and power costs relating to
our pipeline and trucking operations. The increased costs will be largely offset
by an 11% increase in the tariff rate on the All American Pipeline effective
January 1, 2002. Also, the crude oil market moved from a backwardated to a flat
and contango market during March of 2001 and remained that way during most of
the remainder of 2001. A flat to contango crude oil market generally means lower
gross margin from our gathering and marketing activities. With countercyclical
balance provided by our storage and terminalling assets, a contango market
creates other arbitrage opportunities and an increase in the usage of our
tankage in Cushing and in the field. During 2001, this countercyclical balance
served to offset a portion of the weaker gathering and marketing margins. A
continued prolonged flat crude oil market will continue to adversely affect our
margins from gathering and marketing, while generally providing fewer arbitrage
opportunities than exist in a contango market.
A significant portion of our gross margin is derived from pipeline
transportation margins associated with the Santa Ynez and Point Arguello fields
located offshore California. While the rate of decline has reduced 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. In
addition, any production disruption from these fields due to production
problems, transportation problems or other reasons could have a material adverse
effect on our business.
RELATED PARTY TRANSACTIONS
We have a long-term agreement with Plains Resources pursuant to which we
purchase for resale at market prices all of Plains Resources equity crude oil
production for a fee of $0.20 per barrel. In November 2001, the agreement
automatically extended for three years. The fee is subject to adjustment every
three years based on then-existing market conditions. For the year ended
December 31, 2001, we paid approximately $223 million for Plains Resources'
production and recognized gross margin of approximately $1.8 million. For a
description of this and other related party transactions, see Item 13.
"Certain Relationships and Related Transactions".
43
RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
141 "Business Combinations" and SFAS. 142 "Goodwill and Other Intangible Assets"
SFAS 141 requires all business combinations initiated after June 30, 2001 (see
Note 4), to be accounted for under the purchase method. For all business
combinations for which the date of acquisition is after June 30, 2001, this
Standard also establishes specific criteria for the recognition of intangible
assets separately from goodwill. We have adopted SFAS 142 effective January 1,
2002. SFAS 142 changes the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years. In
conjunction with the adoption of SFAS 142, amortization on the unamortized
portion of the goodwill arising from previous acquisitions will cease in 2002.
The adoption of SFAS 142 will not have a material effect on either our financial
position, results of operations, or cash flows.
In June 2001, the FASB also issued SFAS 143, "Asset Retirement Obligations".
SFAS 143 establishes accounting requirements for retirement obligations
associated with tangible long-lived assets, including (1) the time of the
liability recognition, (2) initial measurement of the liability, (3) allocation
of asset retirement cost to expense, (4) subsequent measurement of the liability
and (5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long-
lived asset and subsequently allocated to expense using a systematic and
rational method. We will adopt the statement effective January 1, 2003, as
required. The transition adjustment resulting from the adoption of SFAS 143 will
be reported as a cumulative effect of a change in accounting principle. At this
time, we cannot reasonably estimate the effect of the adoption of this statement
on either our financial position, results of operations, or cash flows.
In August 2001, the FASB approved SFAS 144, "Accounting for Impairment or
Disposal of Long-Lived Assets". SFAS 144 establishes a single accounting model
for long-lived assets to be disposed of by sale and provides additional
implementation guidance for assets to be held and used and assets to be disposed
of other than by sale. Upon adoption of this Statement effective January 1,
2002, there was no effect on either our financial position, results of
operations or cash flows.
In June 1998, the FASB issued SFAS 133, which was subsequently amended (i)
in June 1999 by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB Statement No. 133", which
deferred the effective date of SFAS 133 to fiscal years beginning after June 15,
2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedge Activities", which amended certain provisions,
inclusive of the definition of the normal purchase and sale exclusion. We have
determined that our physical purchase and sale agreements qualify for the normal
purchase and sale exclusion.
SFAS 133 requires that all derivative instruments be recorded on the balance
sheet as either assets or liabilities measured at their fair value. Changes in
the fair value of derivatives are recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction and, if so, the type of hedge transaction. For fair
value hedge transactions in which we are hedging changes in the fair value of an
asset, liability, or firm commitment, changes in the fair value of the
derivative instrument will generally be offset in the income statement by
changes in the fair value of the hedged item. For cash flow hedge transactions,
in which we are hedging the variability of cash flows related to a variable-rate
asset, liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income, a
component of partners' capital. The gains and losses on the derivative
instrument that are reported in other comprehensive income will be reclassified
as earnings in the periods in which earnings are affected by the variability of
the cash flows of the hedged item. The ineffective portion of all hedges will be
recognized in earnings in the current period. Hedge effectiveness is measured at
least quarterly based on the relative cumulative changes in fair value between
the derivative contract and the hedged item over time.
We adopted SFAS 133, as amended, effective January 1, 2001. Our
implementation procedures identified all instruments in place at the adoption
date that are subject to the requirements of SFAS 133. Upon adoption, we
recorded a cumulative effect charge of $8.3 million in accumulated other
comprehensive income to recognize at fair value all derivative instruments that
are designated as cash flow hedging instruments and a cumulative effect gain of
$0.5 million to earnings. Correspondingly, an asset of $2.8 million and a
liability of $10.6 million were established. Hedge losses/gains included in
accumulated other comprehensive income are transferred to earnings as the
forecasted transactions actually occur. Implementation issues continue to be
addressed by the FASB and any change to existing guidance might impact our
implementation. Adoption of this standard will most likely increase volatility
in earnings and partners' capital through comprehensive income.
44
RISK FACTORS RELATED TO OUR BUSINESS
Our profitability is dependent upon an adequate supply of crude oil from fields
located offshore and onshore California. Production from these offshore fields
has experienced substantial production declines since 1995.
A significant portion of our gross margin is derived from pipeline
transportation margins associated with the Santa Ynez and Point Arguello fields
located offshore California. Although the rate of decline from these fields 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. See "Outlook". In addition, any production
disruption from these fields due to production problems, transportation problems
or other reasons could have a material adverse effect on our business.
Cash distributions are not guaranteed and may fluctuate with our performance
and the establishment of financial reserves.
Because distributions on the common units are dependent on the amount of
cash we generate, distributions may fluctuate based on our performance. We
cannot guarantee that we will be able to pay the minimum quarterly distributions
of $0.45 per common unit in each quarter. The actual amount of cash that is
available to be distributed each quarter will depend upon numerous factors, some
of which are beyond our control and the control of our general partner. Cash
distributions are dependent primarily on cash flow, including cash flow from
financial reserves and working capital borrowings, and not solely on
profitability, which is affected by non-cash items. Therefore, cash
distributions might be made during periods when we record losses and might not
be made during periods when we record profits.
Potential future acquisitions and expansions, if any, may affect our business
by substantially increasing the level of our indebtedness and contingent
liabilities and increasing our risks of being unable to effectively integrate
these new operations.
From time to time, we evaluate and acquire assets and businesses that we
believe complement our existing assets and businesses. Acquisitions may require
substantial capital or the incurrence of substantial indebtedness. If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly and you will not have the opportunity to evaluate the
economic, financial and other relevant information that we will consider in
determining the application of these funds and other resources.
In 1999, we suffered a large loss from unauthorized crude oil trading by a
former employee. A loss of this kind could occur again in the future in spite
of our efforts to prevent it.
Generally, it is our policy that as we purchase crude oil, we establish a
margin 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 under futures contracts on the NYMEX. Through these
transactions, we seek to maintain a position that is substantially balanced
between purchases, on the one hand, and sales or future delivery obligations, on
the other hand. Except for pre-defined inventory positions described in Items 1
and 2. "Business and Properties--Terminalling, Storage, Gathering and Marketing
Operations--Crude Oil Volatility; Counter-Cyclical Balance; Risk Management",
our policy is not to acquire and hold crude oil, futures contracts or derivative
products for the purpose of speculating on price changes. We discovered in
November 1999 that this policy was violated by one of our former employees,
which resulted in losses of approximately $174.0 million, 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. We
have taken steps within our organization to enhance our processes and procedures
to prevent future unauthorized trading. We cannot assure you, however, that
these steps will detect and prevent all violations of our trading policies and
procedures, particularly if deception or other intentional misconduct is
involved. See Items 1 and 2. "Business and Properties--Unauthorized Trading
Loss".
We have substantial leverage that may limit our ability to borrow additional
funds, make distributions to unitholders, comply with the terms of our
indebtedness or capitalize on business opportunities.
Our leverage is significant in relation to our partners' capital. As of
December 31, 2001, our total outstanding long-term debt was approximately $352
million. Our payment of principal and interest on the debt will reduce the cash
available for distribution on the units. We will be prohibited from making cash
distributions during an event of default under any of our indebtedness. Various
limitations in our credit facilities may reduce our ability to incur additional
debt, to engage in some transactions and to capitalize on business
opportunities. Any subsequent refinancing of our current indebtedness or any new
indebtedness could have similar or greater restrictions. See "--Liquidity and
Capital Resources".
45
The success of our business strategy to increase and optimize throughput on our
pipeline and gathering assets is dependent upon our securing additional
supplies of crude oil.
Our operating results are dependent upon securing additional supplies of
crude oil from increased production by oil companies and aggressive lease
gathering efforts. The ability of producers to increase production is dependent
on the prevailing market price of oil, the exploration and production budgets of
the major and independent oil companies, the depletion rate of existing
reservoirs, the success of new wells drilled, environmental concerns, regulatory
initiatives and other matters beyond our control. There can be no assurance that
production of crude oil will rise to sufficient levels to cause an increase in
the throughput on our pipeline and gathering assets.
Our operations are dependent upon demand for crude oil by refiners in the
Midwest and on the Gulf Coast. Any decrease in this demand could adversely
affect our business.
Demand also depends on the ability and willingness of shippers having access
to our transportation assets to satisfy their demand by deliveries through those
assets, and any decrease in this demand could adversely affect our business.
Demand for crude oil is dependent upon the impact of future economic conditions,
fuel conservation measures, alternative fuel requirements, governmental
regulation or technological advances in fuel economy and energy generation
devices, all of which could reduce demand.
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. See Items 1 and 2.
"Business and Properties--Competition".
The profitability of our gathering and marketing activities depends primarily
on the volumes of crude oil we purchase and gather.
To maintain the volumes of crude oil we purchase, we must continue to
contract for new supplies of crude oil to offset volumes lost because of natural
declines in crude oil production from depleting wells or volumes lost to
competitors. Replacement of lost volumes of crude oil is particularly difficult
in an environment where production is low and competition to gather available
production is intense. Generally, because producers experience inconveniences in
switching crude oil purchasers, such as delays in receipt of proceeds while
awaiting the preparation of new division orders, producers typically do not
change purchasers on the basis of minor variations in price. Thus, we may
experience difficulty acquiring crude oil at the wellhead in areas where there
are existing relationships between producers and other gatherers and purchasers
of crude oil.
We are exposed to the credit risk of our customers in the ordinary course of
our gathering and marketing activities.
In those cases where we provide division order services for crude oil
purchased at the wellhead, we may be responsible for distribution of proceeds to
all parties. In other cases, we pay all of or a portion of the production
proceeds to an operator who distributes these proceeds to the various interest
owners. These arrangements expose us to operator credit risk, and there can be
no assurance that we will not experience losses in dealings with other parties.
Our operations are subject to federal and state environmental and safety laws
and regulations relating to environmental protection and operational safety.
Our pipeline, gathering, storage and terminalling facilities operations are
subject to the risk of incurring substantial environmental and safety related
costs and liabilities. These costs and liabilities could arise under
increasingly strict environmental and safety laws, including regulations and
enforcement policies, or claims for damages to property or persons resulting
from our operations. If we were not able to recover such resulting costs through
insurance or increased tariffs and revenues, cash distributions to unitholders
could be adversely affected.
The transportation and storage of crude oil results in a risk that crude oil
and other hydrocarbons may be suddenly or gradually released into the
environment, potentially causing substantial expenditures for a response action,
significant government penalties, liability for natural resources damages to
government agencies, personal injury or property damage to private parties and
significant business interruption. See Items 1 and 2. "Business and Properties--
Regulation".
Our pipeline systems are dependent upon their interconnections with other crude
oil pipelines to reach end markets.
Reduced throughput on these interconnecting pipelines as a result of
testing, line repair, reduced operating pressures or other causes could result
in reduced throughput on our pipeline systems that would adversely affect our
profitability.
46
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in crude oil
commodity prices and interest rates. To manage such exposure, we monitor our
inventory levels, current economic conditions and our expectations of future
commodity prices and interest rates when making decisions with respect to risk
management. Except for inventory transactions that generally do not exceed
approximately 500,000 barrels, we do not enter into derivative transactions for
speculative trading purposes. See Items 1 and 2. "Business and Properties--Crude
Volatility; Counter-Cyclical Balance; Risk Management". Substantially all of our
derivative contracts are exchanged or traded on the NYMEX or entered into with
major financial institutions and the risk of credit loss is considered remote.
Commodity Price Risk. The fair value of outstanding derivative instruments
and the change in fair value that would be expected from a 10 percent price
decrease are shown in the table below (in millions):
YEAR OF MATURITY
-------------------------------------------------------------------------------
2002 2003
------------------------------------ --------------------------------------
EFFECT OF EFFECT OF
FAIR 10% PRICE FAIR 10% PRICE
VALUE DECREASE VALUE DECREASE
------------ ---------------- ---------------- ---------------
Crude oil :
Futures contracts $(1.8) $(0.7) $0.7 $(4.2)
Swaps and options contracts - - - -
The fair values of the futures contracts are based on quoted market prices
obtained from the NYMEX. The fair value of the swaps and option contracts are
estimated based on quoted prices from independent reporting services compared to
the contract price of the swap, which comparison approximates the gain or loss
that would have been realized if the contracts had been closed out at year end.
All hedge positions offset physical positions exposed to the cash market; none
of these offsetting physical positions are included in the above table. Price-
risk sensitivities were calculated by assuming an across-the-board 10 percent
decrease in price regardless of term or historical relationships between the
contractual price of the instruments and the underlying commodity price. In the
event of an actual 10 percent change in prompt month crude prices, the fair
value of our derivative portfolio would typically change less than that shown in
the table due to lower volatility in out-month prices.
At December 31, 2001, our hedging activities included crude oil futures
contracts maturing through 2003, covering approximately 2.4 million barrels of
product. Because such contracts are designated as hedges and correlate to price
movements of crude oil, any gains or losses resulting from market changes will
be largely offset by losses or gains on our hedged inventory or anticipated
purchases of crude oil. Such contracts resulted in an increase in revenues of
$1.8 million in 2001 and a reduction in revenues of $15.1 million in 2000 and of
$17.8 million in 1999. The offsetting gains from the physical positions are not
included in such amounts. The unrealized loss with respect to such instruments,
interest rate hedges and foreign exchange hedges, at December 31, 2001, was $4.7
million.
Interest Rate Risk. Our debt instruments are sensitive to market
fluctuations in interest rates. The table below presents principal payments and
the related weighted average interest rates by expected maturity dates for debt
outstanding at December 31, 2001. Our variable rate debt bears interest at LIBOR
or prime plus the applicable margin. The average interest rates presented below
are based upon rates in effect at December 31, 2001. The carrying value of
variable rate bank debt approximates fair value because interest rates are
variable and based on prevailing market rates (dollars in millions).
EXPECTED YEAR OF MATURITY
-------------------------------------------------------------------------------- FAIR
2002 2003 2004 2005 2006 THEREAFTER TOTAL VALUE
------ ----- ------ ------ ------ --------- ------- -------
Liabilities:
Short-term debt (and current
maturities of long-term debt) -
variable rate $104.5 $ - $ - $ - $ - $ - $ 104.5 $ 104.5
Average interest rate 3.7% - - - - - 3.7%
Long-term debt - variable rate $ - $ 9.0 $ 10.0 $ 64.7 $ 78.0 $ 190.0 $ 351.7 $ 351.7
Average interest rate - 4.4% 4.4% 4.4% 4.4% 4.5% 4.4%
At December 31, 2001, the carrying value of short-term and long-term debt of
$104.5 million and $351.7 million, respectively, approximated fair value.
47
Interest rate swaps and collars are used to hedge underlying interest payment
obligations. These instruments hedge interest rates on specific debt issuances
and qualify for hedge accounting. The interest rate differential is reflected as
an adjustment to interest expense over the life of the instruments. At December
31, 2001, we had interest rate swap and collar arrangements for an aggregate
notional principal amount of $275.0 million, for which we would pay
approximately $5.3 million if such arrangements were terminated as of such date.
The table shown below summarizes the fair value of our interest rate swaps and
collars by the year of maturity (in thousands):
Year of Maturity
------------------------------------------
2002 2003 2004 Total
-------- -------- ------- --------
Interest rate swaps $ -- $ (810) $ (689) $ (1,499)
Interest rate collars (3,777) -- -- (3,777)
-------- -------- -------- --------
Total $ (3,777) $ (810) $ (689) $ (5,276)
======== ======== ======== ========
The adjustment to interest expense resulting from interest rate swaps for
the years ended December 31, 2001, 2000 and 1999, was a $2.4 million loss, a
$0.1 million gain and a $0.1 million loss, respectively. These instruments are
based on LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of
8.0% with an expiration date of August 2002 for $125.0 million notional
principal amount. The fixed rate interest rate swaps provide for a rate of 4.3%
for $50.0 million notional principal amount expiring March 2004, and an average
rate of 3.6% for $100.0 million notional principal amount expiring September
2003.
Foreign Currency Risk. Our cash flow stream relating to our Canadian
operations is based on the U.S. dollar equivalent of such amounts measured in
Canadian dollars. Assets and liabilities of our Canadian subsidiaries are
translated to U.S. dollars using the applicable exchange rate as of the end of a
reporting period. Revenues, expenses and cash flow are translated using the
average exchange rate during the reporting period.
Since substantially all of our Canadian business is conducted in Canadian
dollars, we use certain financial instruments to minimize the risks of changes
in the exchange rate. These instruments include forward exchange contracts,
forward extra option contracts and cross currency swaps. Additionally, at
December 31, 2001, $25.4 million ($40.5 million Canadian) of our long-term debt
was denominated in Canadian dollars. All of the financial instruments utilized
are placed with large creditworthy financial institutions that participate in
our credit facilities and meet the criteria under SFAS 133 for hedge accounting
treatment.
At December 31, 2001, we had forward exchange contracts and forward extra
option contracts that allow us to exchange $3.0 million Canadian for at least
$1.9 million U.S. (based on a Canadian-U.S. dollar exchange rate of 1.55)
quarterly during 2002 and 2003. If these contracts were terminated on December
31, 2001, we would receive $0.5 million U.S. At December 31, 2001, we also had a
cross currency swap contract for an aggregate notional principal amount of $25.0
million, effectively converting this amount of our $100.0 million senior secured
term loan (25% of the total) from U.S. dollars to $38.7 million of Canadian
dollar debt (based on a Canadian U.S. dollar exchange rate of 1.55). The terms
mirror the term loan, matching the amortization schedule and final maturity in
May 2006. If this swap contract was terminated on December 31, 2001, we would
receive $0.5 million U.S. dollars.
The table shown below summarizes the fair value of our foreign currency
hedges by year of maturity (in thousands):
YEAR OF MATURITY
-------------------------------------------------------
2002 2003 2006 (1) TOTAL
-------- -------- -------- --------
Forward exchange contracts $ 123 $ 100 $ - $ 223
Forward extra options 145 146 - 291
Cross currency swaps - - 497 497
-------- -------- -------- --------
Total $ 268 $ 246 $ 497 $ 1,011
======== ======== ======== ========
_________________
(1) At December 31, 2001, we did not have any foreign currency hedges
expiring in 2004 or 2005.
48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the report as set forth in
the "Index to Financial Statements" on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
49
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
PARTNERSHIP MANAGEMENT
As is the case with many publicly traded partnerships, we do not have
officers, directors or employees. Our operations and activities are managed by
the general partner of our general partner, Plains All American GP LLC. Our
operational personnel are employees of Plains All American GP LLC. References to
our general partner, unless the context otherwise requires, includes Plains All
American GP LLC. References to our officers, directors and employees are
references to the officers, directors and employees of Plains All American GP
LLC.
Our general partner manages our operations and activities. Unitholders do not
directly or indirectly participate in our management or operation. Our general
partner owes a fiduciary duty to the unitholders, as limited by our partnership
agreement. As a general partner, our general partner is liable for all of our
debts (to the extent not paid from our assets), except for indebtedness or other
obligations that are made specifically non-recourse to it. Whenever possible,
our general partner intends to incur indebtedness or other obligations on a non-
recourse basis.
Two members of the board of directors of our general partner serve on a
conflicts committee, which reviews specific matters that the board believes may
involve conflicts of interest between our general partner and Plains All
American Pipeline. The conflicts committee determines if the resolution of a
conflict of interest is fair and reasonable to us. The members of the conflicts
committee are not officers or employees of our general partner or directors,
officers or employees of its affiliates. Any matters approved by the conflicts
committee will be conclusively deemed to be fair and reasonable to us, approved
by all of our partners, and not a breach by our general partner of any duties
owed to us or our unitholders. The members of the conflicts committee also serve
with another director on an audit committee, which reviews our external
financial reporting, recommends engagement of our independent auditors and
reviews the adequacy of our internal accounting controls.
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information with respect to the
executive officers and members of the Board of Directors of our general partner.
Directors were elected in June 2001 for an initial three-year term, and will be
elected annually thereafter. Certain owners of our general partner have the
right to designate a member of our board. Such designees are indicated in the
footnote to the table.
NAME AGE POSITION WITH OUR GENERAL PARTNER
- ---- --- ---------------------------------
EXECUTIVE OFFICERS AND
DIRECTORS:
Greg L. Armstrong 43 Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis 44 President, Chief Operating Officer and Director
Phillip D. Kramer 46 Executive Vice President and Chief Financial Officer
George R. Coiner 51 Senior Vice President
Mark F. Shires 44 Vice President - Operations
Jim Hester 42 Vice President - Acquisitions
Tim Moore 44 Vice President, General Counsel and Secretary
Alfred A. Lindseth 32 Vice President - Administration
Everardo Goyanes 57 Director and Member of Audit* and Conflicts Committees
Gary R. Petersen(1) 55 Director and Member of Compensation Committee*
John T. Raymond(1) 31 Director and Member of Finance Committee
Robert V. Sinnott(1) 52 Director and Member of Compensation and Finance Committees
Arthur L. Smith 49 Director and Member of Audit, Conflicts* and Compensation
Committees
J. Taft Symonds(1) 62 Director and member of Audit and Finance* Committees
- ---------------
* Indicates chairman of committee
(1) Pursuant to the Amended and Restated Limited Liability Company Agreement of
Plains All American GP LLC, certain of the owners of our general partner
have the right to designate a member of our board of directors. Mr.
Petersen has been designated by E-Holdings III, L.P., an affiliate of EnCap
Investments LLC, of which he is a Managing Director. Mr. Raymond has been
designated by Sable Investments, L.P., in which Mr. Raymond indirectly owns
a limited partner interest. Sable Investments, L.P. is controlled by James
M. Flores, the Chief Executive Officer of Plains Resources. Mr.
50
Sinnott has been designated by KAFU Holdings, L.P., which is affiliated
with Kayne Anderson Investment Management, Inc., of which he is a Vice
President. Mr. Symonds has been designated by Plains Resources, of which he
is a director. See Item 12. "Security Ownership of Certain Beneficial
Owners and Management--Beneficial Ownership of General Partner Interest".
The following table sets forth certain information with respect to other
members of our management team and officers of the general partner of our
Canadian operating partnership:
POSITION WITH OUR GENERAL PARTNER/
NAME AGE CANADIAN GENERAL PARTNER
- ---- --- ----------------------------------
MANAGEMENT TEAM/
OTHER OFFICERS:
A. Patrick Diamond 29 Manager - Special Projects
Lawrence J. Dreyfuss 47 Associate General Counsel and Assistant Secretary;
General Counsel and Secretary of PMC (Nova Scotia)
Company (the general partner of Plains Marketing
Canada, L.P.)
Al Swanson 38 Treasurer
CANADIAN OFFICERS:
W. David Duckett 47 Executive Vice President of PMC (Nova Scotia) Company
Ralph R. Cross 47 Vice President - Business Development of PMC
(Nova Scotia) Company
John Kers 54 Vice President - Operations of PMC (Nova Scotia)
Company
Greg L. Armstrong has served as Chairman of the Board and Chief Executive
Officer since our formation. He has also served as a director of our general
partner or former general partner since our formation. In addition, he was
President, Chief Executive Officer and director of Plains Resources from 1992 to
May 2001. He previously served Plains Resources as: President and Chief
Operating Officer from October to December 1992; Executive Vice President and
Chief Financial Officer from June to October 1992; Senior Vice President and
Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial
Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer
from 1984 to 1987.
Harry N. Pefanis has served as President and Chief Operating Officer since our
formation. He was a director of our former general partner. In addition, he was
Executive Vice President - Midstream of Plains Resources from May 1998 to May
2001. He previously served Plains Resources as: Senior Vice President from
February 1996 until May 1998; Vice President - Products Marketing from 1988 to
February 1996; Manager of Products Marketing from 1987 to 1988; and Special
Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also
President of several former midstream subsidiaries of Plains Resources until our
formation in 1998.
Phillip D. Kramer has served as Executive Vice President and Chief Financial
Officer since our formation. In addition, he was Executive Vice President and
Chief Financial Officer of Plains Resources from May 1998 to May 2001. He
previously served Plains Resources as: Senior Vice President and Chief Financial
Officer from May 1997 until May 1998; Vice President and Chief Financial Officer
from 1992 to 1997; Vice President from 1988 to 1992; Treasurer from 1987 to
March 2001; and Controller from 1983 to 1987.
George R. Coiner has served as Senior Vice President since our formation. In
addition, he was Vice President of Plains Marketing & Transportation Inc., a
former midstream subsidiary of Plains Resources, from November 1995 until our
formation in 1998. Prior to joining Plains Marketing & Transportation Inc., he
was Senior Vice President, Marketing with Scurlock Permian Corp.
Mark F. Shires has served as Vice President - Operations since August 1999. He
served as Manager of Operations from April 1999 until he was elected to his
current position. In addition, he was a business consultant from 1996 until
April 1999. He served as a consultant to Plains Marketing & Transportation Inc.
and Plains All American Pipeline from May 1998 until April 1999. He previously
served as President of Plains Terminal & Transfer Corporation, a former
midstream subsidiary of Plains Resources, from 1993 to 1996.
Jim G. Hester has served as Vice President - Acquisitions since March 2002.
Prior to joining us, Mr. Hester was Senior Vice President - Special Projects of
Plains Resources. From May 2001 to December 2001, he was Senior Vice President -
Operations for Plains Resources. From May 1999 to May 2001, he was Vice
President - Business Development and Acquisitions of Plains Resources. He was
Manager of Business Development and Acquisitions of Plains Resources from 1997
to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of
Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to
1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor
from 1988 to 1990.
51
Tim Moore has served as Vice President, General Counsel and Secretary since
May 2000. In addition, he was Vice President, General Counsel and Secretary of
Plains Resources from May 2000 to May 2001. Prior to joining Plains Resources,
he served in various positions, including General Counsel - Corporate, of
TransTexas Gas Corporation from 1994 to 2000. He previously was a corporate
attorney with the Houston office of Weil Gotshal & Manges. Mr. Moore also has
seven years of industry experience as a petroleum geologist.
Alfred A. Lindseth has served as Vice President - Administration since March
2001. He served as Risk Manager from March 2000 until he was elected to his
current position. He previously served PricewaterhouseCoopers LLP in its
Financial Risk Management Practice section as a Consultant from 1997 to 1999 and
as Principal Consultant from 1999 to March 2000. He also served GSC Energy, an
energy risk management brokerage and consulting firm, as Manager of its Oil &
Gas Hedging Program from 1995 to 1996 and as Director of Research and Trading
from 1996 to 1997.
Everardo Goyanes has served as a director of our general partner or former
general partner since May 1999. Mr. Goyanes has been President and Chief
Executive Officer of Liberty Energy Holdings since May 2000. From 1999 to May
2000 he was a financial consultant specializing in natural resources. From 1989
to 1999, he was Managing Director of the Natural Resources Group of ING Barings
Furman Selz. He was a financial consultant from 1987 to 1989 and was Vice
President - Finance of Forest Oil Corporation from 1983 to 1987. Mr. Goyanes is
also a director of Consort Group Limited.
Gary R. Petersen has served as a director since June 2001. Mr. Petersen co-
founded EnCap Investments L.L.C. (an investment management firm) and has been a
Managing Director and principal of the firm since 1988. He had previously served
as Senior Vice President and Manager of the Corporate Finance Division of the
Energy Banking Group for RepublicBank Corporation. Prior to his position at
RepublicBank, he was Executive Vice President and a member of the Board of
Directors of Nicklos Oil & Gas Company in Houston, Texas from 1979 to 1984. He
served from 1970 to 1971 in the U.S. Army as a First Lieutenant in the Finance
Corps and an Army Officer in the National Security Agency.
John T. Raymond has served as a director since June 2001. Mr. Raymond has also
served as Executive Vice President and Chief Operating Officer of Plains
Resources from May 2001 to November 2001 and President and Chief Operating
Officer since November 2001. He was Director of Corporate Development of Kinder
Morgan, Inc. from January 2000 to May 2001. He served as Vice President of
Corporate Development of Ocean Energy, Inc. from April 1998 to January 2000. He
was a Vice President of Howard Weil Labouisse Friedrichs, Inc. from 1992 to
April 1998.
Robert V. Sinnott has served as a director of our general partner or former
general partner since September 1998. Mr. Sinnott has been a Senior Managing
Director of Kayne Anderson Capital Advisors, L.P. (an investment management
firm) since 1996, and was a Managing Director from 1992 to 1996. He was Vice
President and Senior Securities Officer of the Investment Banking Division of
Citibank from 1986 to 1992. He is also a director of Plains Resources and
Glacier Water Services, Inc. (a vended water company).
Arthur L. Smith has served as a director of our general partner or former
general partner since February 1999. Mr. Smith is Chairman of John S. Herold,
Inc. (a petroleum research and consulting firm), a position he has held since
1984. For the period from May 1998 to October 1998, he served as Chairman and
Chief Executive Officer of Torch Energy Advisors Incorporated. He is also a
director of Cabot Oil & Gas Corporation and Evergreen Resources, Inc.
J. Taft Symonds has served as a director since June 2001. He has been Chairman
of the Board of Symonds Trust Co. Ltd. (an investment firm) and Chairman of the
Board of Maurice Pincoffs Company, Inc. (an international marketing firm) since
1978. He is also Chairman of the Board of Tetra Technologies, Inc. (an oilfield
services firm) and a director of Denali, Inc. (a manufacturer of storage tanks
and a product and service provider for handling of industrial fluids). Mr.
Symonds is also a director of Plains Resources Inc.
A. Patrick Diamond has served as Manager, Special Projects since June 2001. In
addition, he was Manager, Special Projects of Plains Resources from August 1999
to June 2001. Prior to joining Plains Resources, Mr. Diamond served Salomon
Smith Barney Inc. in its Global Energy Investment Banking Group as a Financial
Analyst from July 1994 to June 1997 and as an Associate from July 1997 to May
1999.
Lawrence J. Dreyfuss has served as Associate General Counsel and Assistant
Secretary of our general partner since June 2001 and held a senior management
position in the Law Department since May 1999. In addition, he was a Vice
President of Scurlock Permian LLC from 1987 to 1999.
Al Swanson has served as Treasurer since May 2001. In addition, he held
several positions at Plains Resources including Treasurer from February 2001 to
May 2001 and Director of Treasury from November 2000 to February 2001. Prior to
joining Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation
from 1999 to October 2000 and in various capacities at Snyder Oil Corporation
including Director Corporate Finance from 1998, Controller - SOCO Offshore, Inc.
52
from 1997, and Accounting Manager from 1992. Mr. Swanson began his career with
Apache Corporation in 1986 serving in internal audit and accounting.
W. David Duckett has been Executive Vice President of PMC (Nova Scotia)
Company since July 2001. Mr. Duckett was previously with CANPET Energy Group
Inc. since 1985, where he served in various capacities, including most recently
as President, Chief Executive Officer and Chairman of the Board.
Ralph W. Cross has been Vice President of Business Development of PMC (Nova
Scotia) Company since July 2001. Mr. Cross was previously with CANPET Energy
Group Inc. since 1992, where he served in various capacities, including most
recently as Vice President of Business Development.
John Kers has been Vice President of Operations for PMC (Nova Scotia) Company
since July 2001. Mr. Kers was previously with Murphy Oil Co. Ltd. since 1980,
where he served in various capacities, including most recently as Manager of
Engineering.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities and Exchange Act of 1934 requires directors,
officers and persons who beneficially own more than ten percent of a registered
class of our equity securities to file with the SEC and the New York Stock
Exchange initial reports of ownership and reports of changes in ownership of
such equity securities. Such persons are also required to furnish us with copies
of all Section 16(a) forms that they file. Based solely upon a review of the
copies of Forms 3, 4 and 5 furnished to us, or written representations from
certain reporting persons that no Forms 5 were required, we believe that during
2001 our officers and directors complied with all filing requirements with
respect to our equity securities. Plains Resources filed a late Form 3 and
six Forms 4 for transactions in 1998, 1999, 2000 and 2001.
REIMBURSEMENT OF EXPENSES OF OUR GENERAL PARTNER AND ITS AFFILIATES
Our general partner does not receive any management fee or other compensation
in connection with its management of Plains All American Pipeline. However, our
general partner performs services for us and is reimbursed by us for all
expenses incurred on our behalf, including the costs of employee, officer and
director compensation and benefits, as well as all other expenses necessary or
appropriate to the conduct of our business. The partnership agreement provides
that our general partner will determine the expenses that are allocable to us in
any reasonable manner determined by our general partner in its sole discretion.
See Item 13. "Certain Relationships and Related Transactions".
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth certain compensation information for our Chief
Executive Officer and the four most highly compensated executive officers other
than the Chief Executive Officer in 2001 (the "Named Executive Officers").
Messrs. Armstrong, Pefanis and Kramer were compensated by Plains Resources prior
to July 2001. However, we reimburse our general partner and its affiliates (and,
for 1999, 2000 and a portion of 2001, we reimbursed our former general partner
and its affiliates, which included Plains Resources) for expenses incurred on
our behalf, including the costs of officer compensation allocable to us. The
Named Executive Officers have also received certain equity-based awards from our
general partner and from our former general partner and its affiliates, which
awards (other than awards under the Long-Term Incentive Plan) are not subject to
reimbursement by us. See "--Long-Term Incentive Plan" and Item 13. "Certain
Relationships and Related Transactions--Transactions with Affiliates".
53
ANNUAL COMPENSATION
------------------------------ OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION (2)
- ---------------------------- ---- ----------- ---------- ----------------
Greg L. Armstrong 2001 $165,000(1) $450,000 (1)(3)
CEO 2000 (1) (1) (1)(3)
1999 (1) (1) (1)(3)
Harry N. Pefanis 2001 $117,500(1) $350,000 (1)(3)
President and COO 2000 (1) (1) (1)(3)
1999 (1) (1) (1)(3)
Phillip D. Kramer 2001 $100,000(1) $100,000 (1)(3)
Executive V.P. and CFO 2000 (1) (1) (1)(3)
1999 (1) (1) (1)(3)
George Coiner 2001 $175,000 $394,100 $10,500(3)
Senior Vice President 2000 175,000 500,700 10,500(3)
1999 180,956 295,000 10,000(3)
Mark F. Shires 2001 $173,333 $175,000 $10,500(3)
Vice President - Operations 2000 155,000 220,000 10,500(3)
1999 160,792(4) 77,500 -
- ---------------
(1) Until July 2001, Messrs. Armstrong, Pefanis and Kramer were employed and
compensated by Plains Resources, which owned our former general partner. We
reimbursed Plains Resources for the portion of their compensation allocable
to us. See Item 13. "Certain Relationships and Related Transactions--
Transactions with Affiliates". Salary amounts shown for the year 2001
reflect compensation paid by our general partner and reimbursed by us for
the last six months of 2001.
(2) Executive officers have received equity-based awards from our general
partner and former general partner and its affiliates. Other than awards
under the general partner's Long-Term Incentive Plan, we do not fund these
awards. Other than awards to non-employee directors, no awards have vested
to date under our Long-Term Incentive Plan. For a description of awards
granted to date under the Long-Term Incentive Plan as well as awards under
other equity-based plans, see "--Long-Term Incentive Plan" and Item 13.
"Certain Relationships and Related Transactions--Transactions with
Affiliates".
(3) Prior to the General Partner Transition, Plains Resources matched 100% of
employees' contribution to its 401(k) Plan (subject to certain limitations
in the plan), with such matching contribution being made 50% in cash and
50% in Plains Resources Common Stock (the number of shares for the stock
match being based on the market value of the Common Stock at the time the
shares were granted). After the General Partner Transition, our general
partner matches 100% of employees' contributions to its 401(k) Plan in
cash, subject to certain limitations in the plan.
(4) Includes $51,000 for consulting fees we paid to Mr. Shires prior to his
becoming an employee in April 1999.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS
Prior to the consummation of the General Partner Transition, Messrs. Armstrong
and Pefanis were employed pursuant to employment agreements with Plains
Resources. Both now have employment agreements with our general partner. Mr.
Armstrong is employed as Chairman and Chief Executive Officer. The primary term
of Mr. Armstrong's employment agreement runs for three years from June 30, 2001.
The term will be automatically extended by one year on each anniversary of the
initial date (June 30, 2001) unless Mr. Armstrong receives notice from the
Chairman of the Compensation Committee that the Board of Directors has elected
not to extend the agreement. Mr. Armstrong has agreed, during the term of the
agreement and for five years thereafter, not to disclose (subject to typical
exceptions) any confidential information obtained by him while employed under
the agreement. The agreement provides for a current base salary of $330,000 per
year, subject to annual review. If Mr. Armstrong's employment is terminated
without cause, he will be entitled to receive an amount equal to his annual base
salary plus his highest annual bonus, multiplied by the lesser of (i) the number
of years (including fractional years) remaining on the agreement and (ii) two.
If Mr. Armstrong terminates his employment as a result of a change in control he
will be entitled to receive an amount equal to three times the aggregate of his
annual base salary and bonus. Under Mr. Armstrong's agreement, a "change of
control" is defined to include (i) the acquisition by an entity or group (other
than Plains Resources and its wholly owned subsidiaries) of 50% or more of our
general partner or (ii) the existing owners of our general partner ceasing to
own more than 50% of our general partner. If Mr. Armstrong's employment is
terminated because of his death, a lump sum payment will be paid to his designee
equal to his annual salary plus his highest annual bonus, multiplied by the
lesser of (i) the number of years (including fractional years) remaining on the
agreement and
54
(ii) two. Under the agreement, Mr. Armstrong will be reimbursed for any excise
tax due as a result of compensation (parachute) payments.
Mr. Pefanis is employed as President and Chief Operating Officer. The primary
term of Mr. Pefanis' employment agreement runs for three years from June 30,
2001. The term will be automatically extended by one year on each anniversary of
the initial date (June 30, 2001) unless Mr. Pefanis receives notice from the
Chairman of the Board of Directors that the Board has elected not to extend the
agreement. Mr. Pefanis has agreed, during the term of the agreement and for one
year thereafter, not to disclose (subject to typical exceptions) any
confidential information obtained by him while employed under the agreement. The
agreement provides for a current base salary of $235,000 per year, subject to
annual review. The provisions in Mr. Pefanis' agreement with respect to
termination, change in control and related payment obligations are substantially
similar to the parallel provisions in Mr. Armstrong's agreement.
LONG-TERM INCENTIVE PLAN
Our general partner has adopted the Plains All American GP LLC 1998 Long-Term
Incentive Plan for employees and directors of our general partner and its
affiliates who perform services for us. The Long-Term Incentive Plan consists of
two components, a restricted unit plan and a unit option plan. The Long-Term
Incentive Plan currently permits the grant of restricted units and unit options
covering an aggregate of 1,425,000 common units. The plan is administered by the
Compensation Committee of our general partner's board of directors. Our general
partner's board of directors in its discretion may terminate the Long-Term
Incentive Plan at any time with respect to any common units for which a grant
has not yet been made. Our general partner's board of directors also has the
right to alter or amend the Long-Term Incentive Plan or any part of the plan
from time to time, including increasing the number of common units with respect
to which awards may be granted; provided, however, that no change in any
outstanding grant may be made that would materially impair the rights of the
participant without the consent of such participant.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the
grantee to receive a common unit upon the vesting of the phantom unit. As of
March 15, 2002, aggregate outstanding grants of approximately 679,000 restricted
units have been made to employees of our general partner. Grants made include
165,000 restricted units to executive officers as a group, including 60,000,
30,000 and 30,000 units to Messrs. Pefanis, Coiner and Shires, respectively.
Additional grants of approximately 288,000 restricted units have been approved,
with vesting in 25% increments if and when the quarterly distribution reaches
$0.525, $0.575 and $0.625 ($2.10, $2.30 and $2.50 annualized), and the criteria
for the remaining 25% yet to be determined. These grants include approximately
203,000 restricted units to executive officers, including 70,000, 10,000,
50,000, 37,500 and 20,000 units to Messrs. Armstrong, Pefanis, Kramer, Coiner
and Shires. The Compensation Committee may, in the future, make additional
grants under the plan to employees and directors containing such terms as the
Compensation Committee shall determine. Restricted units granted to employees
during the subordination period, although additional vesting criteria may
sometimes apply, will vest only after, and in the same proportions as, the
conversion of the subordinated units to common units. Grants made to non-
employee directors of our general partner are eligible to vest prior to
termination of the subordination period. In 2000, the three non-employee
directors of our former general partner (Messrs. Goyanes, Sinnott and Smith)
were each granted 5,000 restricted units. These units vested in connection with
the consummation of the General Partner Transition. Additional grants of 5,000
restricted units will be made in 2002 to each non-employee director of our
general partner. These units will vest in 25% increments on each anniversary of
June 8, 2001. See "--Compensation of Directors".
If a grantee terminates employment or membership on the board for any reason,
the grantee's restricted units will be automatically forfeited unless, and to
the extent, the Compensation Committee provides otherwise. Common units to be
delivered upon the vesting of rights may be common units acquired by our general
partner in the open market or in private transactions, common units already
owned by our general partner, or any combination of the foregoing. Our general
partner will be entitled to reimbursement by us for the cost incurred in
acquiring common units. In addition, we may issue up to 975,000 Common Units to
satisfy delivery obligations under the grants, less any common units issued upon
exercise of unit options under the plan (see below). If we issue new common
units upon vesting of the restricted units, the total number of common units
outstanding will increase. Whether we satisfy vested units with purchases or by
new issuances, the vesting will result in a compensation expense charge to us.
Following the subordination period, the Compensation Committee, in its
discretion, may grant tandem distribution equivalent rights with respect to
restricted units.
The subordination period (as defined in the partnership agreement) will end if
certain financial tests are met for three consecutive four-quarter periods (the
"testing period"), but no sooner than December 31, 2003. During the first
quarter after the end of the subordination period, all of the subordinated units
will convert into common units. Early conversion of a portion of the
subordinated units may occur if the testing period is satisfied before December
31, 2003. We have determined that the first four-quarter period of the testing
period was satisfied as of September 30, 2001. Although we cannot give assurance
in that regard, if we continue to meet the requirements, 25% of the subordinated
units will convert in the fourth quarter of 2003 and the remainder will convert
in the first quarter of 2004. Our ability to continue to meet the requirements
is
55
subject to a number of economic and operational contingencies. See
"Managements Discussion and Analysis--Risk Factors" and "--Forward Looking
Statements".
The issuance of the common units pursuant to the restricted unit plan is
primarily intended to serve as a means of incentive compensation for
performance. Therefore, no consideration will be paid to us by the plan
participants upon receipt of the common units.
Unit Option Plan. The Unit Option Plan currently permits the grant of options
covering common units. No grants have been made under the Unit Option Plan to
date. However, the Compensation Committee may, in the future, make grants under
the plan to employees and directors containing such terms as the committee shall
determine, provided that unit options have an exercise price equal to the fair
market value of the units on the date of grant. Unit options granted during the
subordination period will become exercisable automatically upon, and in the same
proportions as, the conversion of the subordinated units to common units, unless
a later vesting date is provided.
Upon exercise of a unit option, our general partner will deliver common units
acquired by it in the open market or in private transactions or use common units
already owned by our general partner, or any combination of the foregoing. In
addition, we may issue up to 975,000 common units to satisfy delivery
obligations under the grants, less any common units issued upon vesting of
Restricted Units under the Plan. Our general partner will be entitled to
reimbursement by us for the difference between the cost incurred by our general
partner in acquiring such common units and the proceeds received by our general
partner from an optionee at the time of exercise. Thus, the cost of the unit
options will be borne by us. If we issue new common units upon exercise of the
unit options, the total number of common units outstanding will increase, and
our general partner will remit to us the proceeds received by it from the
optioned upon exercise of the unit option.
OTHER EQUITY GRANTS
Certain other employees and officers have also received grants of equity not
associated with the Long-Term Incentive Plan described above, and for which we
have no cost or reimbursement obligations. See Item 13. "Certain Relationships
and Related Transactions - Transactions with Affiliates".
COMPENSATION OF DIRECTORS
Each director of our general partner who is not an employee of our general
partner is paid an annual retainer fee of $20,000, an attendance fee of $2,000
for each board meeting he attends (excluding telephonic meetings), an attendance
fee of $500 for each committee meeting or telephonic board meeting he attends
plus reimbursement for related out-of-pocket expenses. In 2001, Messrs. Goyanes
and Smith each received $10,000 for their service on a special committee of the
Board of Directors of our former general partner. Mr. Armstrong is otherwise
compensated for his services as an employee and therefore receives no separate
compensation for his services as a director. Each committee chairman (other than
the Audit Committee) receives $2,000 annually. The chairman of the Audit
Committee receives $12,000 annually, and the other members of the Audit
Committee receives $4,000 annually.
In 2000, Messrs. Goyanes, Sinnott and Smith, as directors of our former
general partner, received a grant of 5,000 restricted units each under our Long-
Term Incentive Plan. The restricted units vested in 2001 in connection with the
consummation of the General Partner Transition. Each non-employee director of
our general partner will receive a grant of 5,000 restricted units in 2002. The
units will vest in 25% increments annually on each anniversary of June 8, 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
BENEFICIAL OWNERSHIP OF PARTNERSHIP UNITS
The following table sets forth the beneficial ownership of units held by
beneficial owners of 5% or more of the units, by directors and Named Executive
Officers of our general partner and by all directors and executive officers as a
group as of March 15, 2002.
56
PERCENTAGE PERCENTAGE PERCENTAGE
OF CLASS B OF OF PERCENTAGE
COMMON COMMON COMMON CLASS B SUBORDINATED SUBORDINATED OF
NAME OF BENEFICIAL OWNER UNITS UNITS UNITS UNITS UNITS UNITS TOTAL UNITS
- ------------------------ ------ -------- --------- ----------- ------------ ------------ ------------
Plains Resources Inc. (1) 6,626,008 20.8% 1,307,190 100.0% 4,503,039(2) 44.90% 28.75%
Plains Holdings Inc. (1) 6,626,008 20.8% 1,307,190 100.0% 4,503,039(2) 44.90% 28.75%
Goldman, Sachs & Co.(3) 2,054,391 6.4% - - - - 4.70%
Sable Holdings, L.P. (4) - - - - 1,943,423 19.40% 4.49%
KAFU Holdings, L.P. (5) - - - - 1,595,322 15.90% 3.69%
E-Holdings III, L.P. (6) - - - - 874,540 8.70% 2.02%
Greg L. Armstrong 96,106(7) (8) - - 28,593(9) (8) (8)
Harry N. Pefanis 73,975(7) (8) - - 4,602(9) (8) (8)
George R. Coiner 44,026(7) (8) - - - - (8)
Phil Kramer 29,000(7) (8) - - 9,742(9) (8) (8)
Mark F. Shires -(7) - - - - - -
Everardo Goyanes 5,000 (8) - - - - (8)
Gary R. Petersen(6) 3,000 (8) - - - - (8)
John T. Raymond - - - - 97,171(10) (8) (8)
Robert V. Sinnott (5) 10,000 (8) - - - - (8)
Arthur L. Smith 10,000 (8) - - - - (8)
J. Taft Symonds 10,000 (8) - - - - (8)
All directors and
executive
officers as a group 282,774(7) (8) - - 143,981(9) 1.40% (8)
(14 persons)
- ---------------
(1) Plains Resources Inc. is the sole stockholder of Plains Holdings Inc, our
former general partner. The record holders of the Class B Common Units is
Plains Holdings Inc. The record holder of the common units and subordinated
units is Plains Holdings LLC, a wholly owned subsidiary of Plains Holdings
Inc. The address of Plains Resources Inc., Plains Holdings Inc. and Plains
Holdings LLC is 500 Dallas, Suite 700, Houston, Texas 77002.
(2) Includes subordinated units owned by Plains Resources, to be transferred to
certain of our employees pursuant to phantom unit grant agreements, subject
to certain vesting conditions. See Note (9) below.
(3) The address for Goldman, Sachs & Co. and its parent, the Goldman Sachs
Group, Inc., is 85 Broad Street, New York, New York 10004. Goldman, Sachs &
Co., a broker/dealer, and its parent, the Goldman Sachs Group, Inc., are
deemed to have shared voting power and shared disposition power over
2,054,391 common units owned by their customers.
(4) Subordinated Units include 97,171 units contributed to Sable Holdings, L.P.
by John T. Raymond in exchange for a limited partner interest. Mr. Raymond
has the right to reacquire such units. Sable Holdings, L.P. is controlled
by James M. Flores. Mr. Flores is the Chief Executive Officer of Plains
Resources. The address for Sable Holdings, L.P. is 500 Dallas, Suite 700,
Houston, Texas 77002.
(5) KAFU Holdings L.P. is an affiliate of Kayne Anderson Investment Management,
Inc., of which Robert V. Sinnott is a Vice President. Mr. Sinnott
disclaims any deemed beneficial ownership of units held by KAFU Holdings,
L.P. Mr. Sinnott owns a 4.5% limited partner interest in KAFU Holdings,
L.P. The address for KAFU Holdings, L.P. is 1800 Avenue of the Stars, 2nd
Floor, Los Angeles, California 90067.
(6) E-Holdings III, L.P. is an affiliate of EnCap Investments L.L.C. of which
Gary R. Petersen is a Managing Director. Mr. Petersen disclaims any deemed
beneficial ownership of units owned by E-Holdings III, L.P.. The address
for E-Holdings III, L.P. is 1100 Louisiana, Suite 3150, Houston, Texas
77002.
(7) Does not include units granted under the Long-Term Incentive Plan, none of
which will vest within 60 days of the date hereof. See Item 11. "Executive
Compensation--Long-Term Incentive Plan".
(8) Less than one percent.
(9) Includes the following unvested subordinated units, which will vest within
60 days, deliverable pursuant to phantom unit agreements to: Mr. Armstrong
- 8,548; Mr. Pefanis - 4,602; Mr. Kramer - 9,742; and Mr. Moore - 3,873.
See Item 13. "Certain Relationships and Related Transactions--Transactions
with Affiliates--Stock Option Replacement".
(10) Units contributed to Sable Holdings, L.P. in exchange for an indirect
limited partner interest. Mr. Raymond has the right to reacquire such
units. See Note (4 )above.
BENEFICIAL OWNERSHIP OF GENERAL PARTNER INTEREST
Plains AAP, L.P. owns all of our 2% general partner interest and all of our
incentive distribution rights. The effective ownership of Plains AAP, L.P.
(after giving effect to proportionate ownership of its 1% general partner,
Plains All American GP LLC) is as follows: Plains Holdings Inc. - 44%; Sable
Investments, L.P. - 20%; KAFU Holdings, L.P. - 16.418%;
E-Holdings III, L.P. -9%; PAA Management, L.P. - 4%; First Union Investors,
Inc. - 3.382%; Mark E. Strome - 2.134%; Strome Hedgecap Fund, L.P. - 1.066%; and
John T. Raymond - 1% (indirectly held through a limited partner interest in
Sable Investments, L.P.).
PAA Management, L.P. is owned by certain members of senior management,
including Messrs. Armstrong, Pefanis, Kramer, Coiner and Shires.
57
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
OUR GENERAL PARTNER
Our operations and activities are managed by, and our officers and personnel
are employed by, our general partner. Prior to the consummation of the General
Partner Transition, some of the senior executives who managed our business also
managed and operated the business of Plains Resources. The transition of
employment of such executives to our general partner was effected on June 30,
2001. Our general partner does not receive any management fee or other
compensation in connection with its management of our business, but it is
reimbursed for all direct and indirect expenses incurred on our behalf.
Our general partner owns the 2% general partner interest and all of the
incentive distribution rights. Our general partner is entitled to receive
incentive distributions if the amount we distribute with respect to any quarter
exceeds levels specified in our partnership agreement. Under the quarterly
incentive distribution provisions, generally our general partner is entitled to
15% of amounts we distribute in excess of $0.450 per unit, 25% of the amounts we
distribute in excess of $0.495 per unit and 50% of amounts we distribute in
excess of $0.675 per unit.
TRANSACTIONS WITH RELATED PARTIES
General
Before the General Partner Transition, Plains Resources indirectly owned and
controlled our former general partner interest. In 2001, our former general
partner and its affiliates incurred $31.2 million of direct and indirect
expenses on our behalf, which we reimbursed. Of this amount, approximately
$218,000, $655,000 and $127,000 represented allocated salary and bonus (for the
year 2000) reimbursement for the services of Messrs. Armstrong, Pefanis and
Kramer, respectively, as officers of our former general partner. In the year
2000, we reimbursed our former general partner $63.8 million, of which $165,000,
$212,000 and $96,000 represented allocated salary and bonus (for the year 1999)
for Messrs. Armstrong, Pefanis and Kramer. For 1999, the equivalent amounts were
$44.7 million, $142,000, $212,000 and $104,000, respectively.
Plains Resources currently owns an effective 44% of our general partner
interest. We have ongoing relationships with Plains Resources. These
relationships include but are not limited to:
. a separation agreement entered into in connection with the General Partner
Transition pursuant to which (i) Plains Resources has indemnified us for (a)
claims relating to securities laws or regulations in connection with the
upstream or midstream businesses, based on alleged acts or omissions
occurring on or prior to June 8, 2001, or (b) claims related to the upstream
business, whenever arising, and (ii) we have indemnified Plains Resources for
claims related to the midstream business, whenever arising. Plains Resources
also has agreed to indemnify and maintain liability insurance for the
individuals who were, on or before June 8, 2001, directors or officers of
Plains Resources or our former general partner.
. a Pension and Employee Benefits Assumption and Transition Services Agreement
that provided for the transfer to our general partner of the employees of our
former general partner and certain headquarter employees of Plains Resources.
. an Omnibus Agreement that provides for the resolution of certain conflicts
arising from the fact that we and Plains Resources conduct related
businesses;
. a Marketing Agreement with Plains Resources that provides for the marketing
of Plains Resources' equity crude oil production. Under the Marketing
Agreement, we purchase for resale at market prices all of Plains Resources
equity production for a fee of $0.20 per barrel. 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. The fee is subject to adjustment every three
years based on then-existing market conditions. For the year ended December
31, 2001, Plains Resources produced approximately 24,500 barrels per day that
were subject to the Marketing Agreement. We paid approximately $223 million
for such production and recognized gross margin of approximately $1.8 million
under the terms of that agreement. In our opinion, these purchases were made
at prevailing market prices. In November 2001, the agreement automatically
extended for an additional three-year period; and
. a Letter Agreement with Plains Resources that provides that if the Marketing
Agreement terminates before our crude oil sales agreement with Tosco Refining
Co. terminates, we will continue to purchase Plains Resources' equity crude
oil production from the Arroyo Grande field under the same terms as the
Marketing Agreement until our Tosco sales agreement terminates.
58
Transaction Grant Agreements
In connection with our initial public offering, our former general partner, at
no cost to us, agreed to transfer, subject to vesting, approximately 400,000 of
its affiliates' common units (including distribution equivalent rights
attributable to such units) to certain key officers and employees of our former
general partner and its affiliates. Of this amount, 75,000 common units were
allocated to each of Messrs. Armstrong and Pefanis, 50,000 common units were
allocated to Mr. Coiner and 30,000 were allocated to Mr. Kramer. Under these
grants, the common units vested based on attaining a targeted operating surplus
for a given year. Of the 400,000 units subject to the transaction grant
agreements, 69,444 units vested in 2000 for 1999's operating results and 133,336
units vested in 2001 for 2000's operating results. The remainder (197,200 units)
vested in connection with the consummation of the General Partner Transition.
Distribution equivalent rights were paid in cash at the time of the vesting of
the associated common units. The values of the units and associated distribution
equivalent rights that vested under the Transaction Grant Agreements for all
grantees in 2001, 2000 and 1999 were $5.7 million, $3.1 million and
$1.0 million, respectively. Although we recorded noncash compensation
expenses with respect to these vestings, the compensation expense incurred in
connection with these grants was funded by our former general partner, without
reimbursement by us.
Long-Term Incentive Plan
Our general partner has adopted the Plains All American LLC 1998 Long-Term
Incentive Plan for employees and directors of our general partner and its
affiliates who perform services for us. The Long-Term Incentive Plan consists of
two components, a restricted unit plan and a unit option plan. The Long-Term
Incentive Plan currently permits the grant of restricted units and unit options
covering an aggregate of 1,425,000 common units. The plan is administered by the
Compensation Committee of our general partner's board of directors.
A restricted unit is a "phantom" unit that entitles the grantee to receive a
common unit upon the vesting of the phantom unit. As of March 15, 2002,
aggregate outstanding grants of approximately 679,000 restricted units have been
made to employees of our general partner. Grants made include 165,000 restricted
units to executive officers as a group, including 60,000, 30,000 and 30,000
units to Messrs. Pefanis, Coiner and Shires, respectively. Additional grants of
approximately 288,000 restricted units have been approved, with vesting in 25%
increments when the quarterly distribution reaches $0.525, $0.575 and $0.625
($2.10, $2.30 and $2.50 annualized), and the criteria for the remaining 25% yet
to be determined. These grants include approximately 203,000 restricted units to
executive officers, including 70,000, 10,000, 50,000, 37,500 and 20,000 units
to Messrs. Armstrong, Pefanis, Kramer, Coiner and Shires.
In 2000, the three non-employee directors of our former general partner
(Messrs. Goyanes, Sinnott and Smith) were each granted 5,000 restricted units.
These units vested in connection with the consummation of the General Partner
Transition. Additional grants of 5,000 restricted units will be made in 2002 to
each non-employee director of our general partner. These units will vest in 25%
increments on each anniversary of June 8, 2001. See "Executive Compensation--
Compensation of Directors".
Performance Option Plan
In connection with the General Partner Transition, the owners of the general
partner (other than PAA Management, L.P.) contributed an aggregate of 450,000
subordinated units to the general partner to provide a pool of units available
for the grant of options to management and key employees. In that regard, the
general partner adopted the Plains All American 2001 Performance Option Plan,
pursuant to which options to purchase approximately 332,500 units have been
granted. Of this amount, 75,000, 55,000, 45,000, 42,500 and 20,000 were granted
to Messrs. Armstrong, Pefanis, Kramer, Coiner and Shires, respectively. Such
options vest in 25% increments based upon achieving quarterly distribution
levels on our units of $0.525, $0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50
and $2.70, annualized). The options will vest immediately upon a change in
control (as defined in the grant agreements). The purchase price under the
options is $22 per subordinated unit, declining over time in an amount equal to
80% of each quarterly distribution per unit. The terms of future grants may
differ from the existing grants. Because the subordinated units underlying the
plan were contributed to the general partner, we will have no obligation to
reimburse the general partner for the cost of the units upon exercise of the
options.
Stock Option Replacement
In connection with the General Partner Transition, certain members of the
management team that had been employed by Plains Resources were transferred to
the general partner. At that time, such individuals held in-the-money but
unvested stock options in Plains Resources, which were subject to forfeiture
because of the transfer of employment. Plains Resources, through its affiliates,
agreed to substitute a contingent grant of subordinated units with a value equal
to the discounted present value of the spread on the unvested options.
Approximately 51,000 subordinated units are subject to such grants, with 34,511
granted to executive officers, including 8,548, 4,602 and 9,742 to Messrs.
Armstrong, Pefanis and Kramer. The subordinated units vest on the same schedule
as the stock options would have vested. The units granted to Messrs. Armstrong,
Pefanis and
59
Kramer will vest in March and April of 2002. The general partner will administer
the vesting and delivery of the units under the grants. Because the units
necessary to satisfy the delivery requirements under the grants will be provided
by Plains Resources, we will have no obligation to reimburse the general partner
for the cost of such units.
Tank Car lease and CANPET
In connection with the CANPET asset acquisition, Plains Marketing Canada,
L.P. assumed CANPET's rights and obligations under a Master Railcar Leasing
Agreement between CANPET and Pivotal Enterprises Corporation ("Pivotal"). The
agreement provides for Plains Marketing Canada, L.P. to lease approximately 57
railcars from Pivotal at a lease price of $1,000 per month, per car. The lease
extends until June of 2008, with an option for Pivotal to extend the term of the
lease for an additional five years. Pivotal is substantially owned by former
employees of CANPET, including W. David Duckett, who is the Executive Vice
President of PMC (Nova Scotia) Company, the general partner of Plains Marketing
Canada, L.P. Mr. Duckett owns a 22% interest in Pivotal. Mr. Duckett, as an
owner of CANPET, will also receive a portion of the proceeds from any contingent
payment of purchase price for the CANPET assets. See Items 1 and 2. "Business
and Properties--Acquisitions and Dispositions--CANPET Energy Group, Inc."
OTHER
Goldman, Sachs & Co., which owns approximately 6% of our common units, was
the sole underwriter of our May 2001 offering of units. The total underwriting
commissions paid in connection with this offering were approximately $4.4
million.
60
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Consolidated Financial Statements" set forth on Page F-1.
(A) (3) EXHIBITS
3.1 -- Third Amended and Restated Agreement of Limited Partnership of Plains
All American Pipeline, L.P. dated as of June 27, 2001 (incorporated
by reference to Exhibit 3.1 to Form 8-K filed August 27, 2001.
3.2 -- Second Amended and Restated Agreement of Limited Partnership of
Plains Marketing, L.P. dated as of June 27, 2001 (incorporated by
reference to Exhibit 3.2 to Form 8-K filed August 27, 2001.
3.3 -- Second Amended and Restated Agreement of Limited Partnership of All
American Pipeline, L.P. dated as of June 27, 2001 (incorporated by
reference to Exhibit 3.3 Form 8-K filed August 27, 2001.
3.4 -- Certificate of Limited Partnership of Plains All American Pipeline,
L.P. (incorporated by reference to Exhibit 3.4 to Registration
Statement, file No. 333-64107).
3.5 -- Certificate of Limited Partnership of Plains Marketing, L.P. dated as
of November 10, 1998 (incorporated by reference to Exhibit 3.5 to
Annual Report on Form 10-K for the Year Ended December 31, 1998).
3.6 -- Articles of Conversion of All American Pipeline Company dated as of
November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual
Report on Form 10-K for the Year Ended December 31, 1998).
3.7 -- Amended and Restated Limited Partnership Agreement of Plains AAP,
L.P., dated as of June 8, 2001 (incorporated by reference to Exhibit
3.1 to Form 8-K filed June 11, 2001).
3.8 -- Amended and Restated Limited Liability Company Agreement of Plains
All American GP, LLC dated as of June 8, 2001 (incorporated by
reference to Exhibit 3.2 to Form 8-K filed June 11, 2001).
4.1 -- Registration Rights Agreement, dated as of June 8, 2001, among Plains
All American Pipeline, L.P., Sable Holdings, L.P., E-Holdings III,
L.P., KAFU Holdings, LP, PAA Management, L.P., Mark E. Strome, Strome
Hedgecap Fund, L.P., John T. Raymond and Plains All American Inc.
(incorporated by reference to Exhibit 4.1 to Form 8-K filed June 11,
2001).
10.01 -- Contribution, Assignment and Amendment Agreement, dated as of
June 27, 2001, among Plains All American Pipeline, L.P., Plains
Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P.,
Plains All American GP LLC and Plains Marketing GP Inc. (incorporated
by reference to Exhibit 10.1 to Form 8-K filed June 27, 2001).
10.02 -- Contribution, Assignment and Amendment Agreement, dated as of
June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and
Plains All American GP LLC (incorporated by reference to Exhibit 10.1
to Form 8-K filed June 11, 2001).
10.03 -- Separation Agreement, dated as of June 8, 2001 among Plains
Resources Inc., Plains All American Inc., Plains All American GP LLC,
Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated
by reference to Exhibit 10.2 to Form 8-K filed June 11, 2001.
10.04 -- Pension and Employee Benefits Assumption and Transition Agreement,
dated as of June 8, 2001 among Plains Resources Inc., Plains All
American Inc. and Plains All American GP LLC (incorporated by
reference to Exhibit 10.3 to Form 8-K filed June 11, 2001).
**10.05 -- Plains All American GP LLC 1998 Long-Term Incentive Plan
(incorporated by reference to Exhibit 99.1 to Registration Statement
on Form S-8, File No. 333-74920).
**10.06 -- Plains All American 2001 Performance Option Plan (incorporated
by reference to Exhibit 99.2 to Registration Statement on Form S-8,
File No. 333-74920).
**10.07 -- Phantom MLP Unit Agreement for Greg L. Armstrong (incorporated
by reference to Exhibit 99.3 to Registration Statement on Form S-8,
File No. 333-74920).
61
**10.08 -- Phantom MLP Unit Agreement for Phillip D. Kramer (incorporated
by reference to Exhibit 99.5 to Registration Statement on Form S-8,
File No. 333-74920).
**10.09 -- Phantom MLP Unit Agreement for Tim Moore (incorporated by reference
to Exhibit 99.6 to Registration Statement on Form S-8,
File No. 333-74920).
**10.10 -- Phantom MLP Unit Agreement for Harry N. Pefanis (incorporated
by reference to Exhibit 99.7 to Registration Statement on Form S-8,
File No. 333-74920).
**10.11 -- Plains All American Inc., 1998 Management Incentive Plan
(incorporated by reference to Exhibit 10.05 to Annual Report on Form
10-K for the Year Ended December 31, 1998).
**10.12 -- Amended and Restated Employment Agreement between Plains All
American GP LLC and Greg L. Armstrong dated as of June 30, 2001
(incorporated by reference to Exhibit 10.3 to Quarterly Report on
Form 10-Q for the Quarter Ended September 30, 2001).
**10.13 -- Amended and Restated Employment Agreement between Plains All
American GP LLC and Harry N. Pefanis dated as of June 30, 2001
(incorporated by reference to Exhibit 10.4 to Quarterly Report on
Form 10-Q for the Quarter Ended September 30, 2001).
10.14 -- Asset Purchase and Sale Agreement between Murphy Oil Company Ltd.
and Plains Marketing Canada, L.P. (incorporated by reference to
Form 8-K filed May 10, 2001.
*10.15 -- Asset Purchase Agreement dated April 9, 2001 between Plains Marketing
L.P., Plains Marketing Canada, L.P., and CANPET Energy Group Inc. and
CANPET Energy Group (USA), Inc.
*10.16 -- Master Railcar Leasing Agreement dated as of May 25, 1998 (effective
June 1, 1998), between Pivotal Enterprises Corporation and CANPET
Energy Group, Inc.
10.17 -- Crude Oil Marketing Agreement among Plains Resources Inc., Plains
Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and
Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by
reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year
Ended December 31, 1998).
10.18 -- Omnibus Agreement among Plains Resources Inc., Plains All American
Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P.,
and Plains All American Inc. dated as of November 23, 1998
(incorporated by reference to Exhibit 10.08 to Annual Report on
Form 10-K for the Year Ended December 31, 1998).
10.19 -- Transportation Agreement dated July 30, 1993, between All American
Pipeline Company and Exxon Company, U.S.A. (incorporated by reference
to Exhibit 10.9 to Registration Statement, file No. 333-64107).
10.20 -- Transportation Agreement dated August 2, 1993, between All American
Pipeline Company and Texaco Trading and Transportation Inc., Chevron
U.S.A. and Sun Operating Limited Partnership (incorporated by
reference to Exhibit 10.10 to Registration Statement, File
No. 333-64107).
**10.21 -- Form of Transaction Grant Agreement (Payment on Vesting)
(incorporated by reference to Exhibit 10.12 to Registration
Statement, file No. 333-64107).
10.22 -- First Amendment to Contribution, Conveyance and Assumption Agreement
dated as of December 15, 1998 (incorporated by reference to Exhibit
10.13 to Annual Report on Form 10-K for the Year Ended December 31,
1998).
10.23 -- Agreement for Purchase and Sale of Membership Interest in Scurlock
Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P.
dated as of March 17, 1999 (incorporated by reference to Exhibit
10.16 to Annual Report on Form 10-K for the Year Ended December 31,
1998).
10.24 -- Asset Sales Agreement between Chevron Pipe Line Company and Plains
Marketing, L.P. dated as of April 16, 1999 (incorporated by reference
to Exhibit 10.17 to Quarterly Report on Form 10-Q for the Quarter
Ended March 31, 1999).
**10.25 -- Transaction Grant Agreement with Greg L. Armstrong (incorporated by
reference to Exhibit 10.20 to Registration Statement on Form S-1,
File no. 333-86907)
**10.26 -- Phantom Unit Grant Agreement for Phillip D. Kramer (incorporated
by reference to Exhibit 99.1 to Registration Statement on Form S-8,
File No. 333-54118).
62
10.27 -- Pipeline Sale and Purchase Agreement dated January 31, 2000, among
Plains All American Pipeline, L.P., All American Pipeline, L.P., El
Paso Natural Gas Company and El Paso Pipeline Company (incorporated
by reference to Exhibit 10.27 to Annual Report on Form 10-K for the
Year Ended December 31, 1999).
10.28 -- Amended and Restated Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated May 4, 2001, among Plains Marketing, L.P,
All American Pipeline, L.P., Plains All American Pipeline, L.P., and
Fleet National Bank and certain other lenders (incorporated by
reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for
the Quarter Ended March 31, 2001).
10.29 -- Amended and Restated Credit Agreement [Revolving Credit Facility]
dated May 4, 2001, among Plains Marketing, L.P, All American
Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
national Bank and certain other lenders (incorporated by reference to
Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter
Ended March 31, 2001).
10.30 -- First Amendment to Credit Agreement [Revolving Credit Facility]
dated as of May 25, 2001 among Plains Marketing, L.P, All American
Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
National Bank and certain other lenders (incorporated by reference to
Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter
Ended June 30, 2001).
10.31 -- First Amendment to Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated as of May 25, 2001, among Plains Marketing,
L.P, All American Pipeline, L.P., Plains All American Pipeline, L.P.,
and Fleet National Bank and certain other lenders (incorporated by
reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for
the Quarter Ended June 30, 2001).
10.32 -- Second Amendment to Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated as of June 26, 2001, among Plains
Marketing, L.P, All American Pipeline, L.P., Plains All American
Pipeline, L.P., and Fleet National Bank and certain other lenders
(incorporated by reference to Exhibit 10.7 to the Quarterly Report on
Form 10-Q for the Quarter Ended June 30, 2001).
10.33 -- Second Amendment to Credit Agreement [Revolving Credit Facility]
dated as of June 26, 2001 among Plains Marketing, L.P, All American
Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
National Bank and certain other lenders (incorporated by reference to
Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarter
Ended June 30, 2001).
10.34 -- Third Amendment to Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated as of September 26, 2001, among
Plains Marketing, L.P, All American Pipeline, L.P., Plains All
American Pipeline, L.P., and Fleet National Bank and certain other
lenders (incorporated by reference to Exhibit 10.1 to the Quarterly
Report on Form 10-Q for the Quarter Ended September 30, 2001).
10.35 -- Third Amendment to Credit Agreement [Revolving Credit Facility]
dated as of September 26, 2001 among Plains Marketing,
L.P, All American Pipeline, L.P., Plains All American Pipeline, L.P.,
and Fleet National Bank and certain other lenders (incorporated by
reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for
the Quarter Ended September 30, 2001).
*10.36 -- Fourth Amendment to Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated October 29, 2001, among Plains Marketing,
L.P, All American Pipeline, L.P., Plains All American Pipeline, L.P.,
and Fleet National Bank and certain other lenders.
*10.37 -- Fourth Amendment to Credit Agreement [Revolving Credit Facility]
dated October 29, 2001 among Plains Marketing, L.P, All American
Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
National Bank and certain other lenders.
*10.38 -- Fifth Amendment to Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated January 31, 2001, among Plains Marketing,
L.P, All American Pipeline, L.P., Plains All American Pipeline, L.P.,
and Fleet National Bank and certain other lenders.
*10.39 -- Fifth Amendment to Credit Agreement [Revolving Credit Facility]
dated as January 31, 2001 among Plains Marketing, L.P, All American
Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
National Bank and certain other lenders.
*21.1 -- Subsidiaries of the Registrant.
*23.1 -- Consent of PricewaterhouseCoopers LLP.
- --------
* Filed herewith
** Management contract or compensatory plan or arrangement
63
(B) REPORTS ON FORM 8-K
A current report on Form 8-K was filed on October 26, 2001 in connection
with the execution of an underwriting agreement with Salomon Smith Barney Inc.,
in connection with the sale by the Partnership of 4,500,000 common units of the
Partnership.
A current report on Form 8-K/A was filed on October 25, 2001 amending the
Partnership's Form 8-K dated June 22, 2001 in connection with the pro forma
financial statements for the Partnership.
64
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
PLAINS ALL AMERICAN PIPELINE, L.P.
By: PLAINS AAP, L.P.,
general partner
By: PLAINS ALL AMERICAN GP LLC,
general partner
Date: March 20, 2002 By: /s/ Phillip D. Kramer
---------------------
Phillip D. Kramer, Executive Vice
President and Chief Financial Officer
(Principal Financial and
Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date: March 20, 2002 By: /s/ Greg L. Armstrong
----------------------------
Greg L. Armstrong, Chairman of the Board
Chief Executive Officer and Director of
Plains All American GP LLC (Principal
Executive Officer)
Date: March 20, 2002 By: /s/ Harry N. Pefanis
--------------------------
Harry N. Pefanis, President and Chief
Operating Officer of
Plains All American GP LLC
Date: March 20, 2002 By: /s/ Phillip D. Kramer
--------------------------
Phillip D. Kramer, Executive Vice
President and Chief Financial Officer
(Principal Financial and Accounting
Officer) of Plains All American GP LLC
Date: March 20, 2002 By: /s/ Everardo Goyanes
-------------------------
Everardo Goyanes, Director of Plains All
American GP LLC
Date: March 20, 2002 By: /s/ Gary R. Petersen
-------------------------
Gary R. Petersen, Director of Plains All
American GP LLC
Date: March 20, 2002 By: /s/ John T. Raymond
------------------------
John T. Raymond, Director of Plains All
American GP LLC
Date: March 20, 2002 By: /s/ Robert V. Sinnott
--------------------------
Robert V. Sinnott, Director of Plains All
American GP LLC
Date: March 20, 2002 By: /s/ Arthur L. Smith
------------------------
Arthur L. Smith, Director of Plains All
American GP LLC
Date: March 20, 2002 By: /s/ J. Taft Symonds
------------------------
J. Taft Symonds, Director of Plains All
American GP LLC
65
PLAINS ALL AMERICAN PIPELINE, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Financial Statements
Report of Independent Accountants................................................................................. F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000...................................................... F-3
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999............................................................................... F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999............................................................................... F-5
Consolidated Statements of Changes in Partners' Capital for the years ended
December 31, 2001, 2000 and 1999............................................................................... F-6
Notes to Consolidated Financial Statements........................................................................ F-7
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of the General Partner and the Unitholders of
Plains All American Pipeline, L.P.
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of changes in partners' capital and of
cash flows present fairly, in all material respects, the financial position of
Plains All American Pipeline, L.P. and its subsidiaries (the "Partnership") at
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Partnership's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, the Partnership
changed its method of accounting for derivatives and hedging activities
effective January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
March 6, 2002
F-2
PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
December 31,
----------------------------------
2001 2000
---------------- ----------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 3,511 $ 3,426
Accounts receivable and other 365,697 347,698
Inventory 188,874 46,780
---------------- ----------------
Total current assets 558,082 397,904
---------------- ----------------
PROPERTY AND EQUIPMENT 653,050 467,619
Less allowance for depreciation and amortization (48,131) (26,974)
---------------- ----------------
604,919 440,645
---------------- ----------------
OTHER ASSETS
Pipeline linefill 57,367 34,312
Other, net 40,883 12,940
---------------- ----------------
$ 1,261,251 $ 885,801
================ ================
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 386,993 $ 328,542
Due to related party 13,685 20,951
Short-term debt and current portion of long-term debt 104,482 1,300
---------------- ----------------
Total current liabilities 505,160 350,793
LONG-TERM LIABILITIES
Bank debt 351,677 320,000
Other long-term liabilities and deferred credits 1,617 1,009
---------------- ----------------
Total liabilities 858,454 671,802
---------------- ----------------
COMMITMENTS AND CONTINGENCIES (Note 14)
PARTNERS' CAPITAL
Common unitholders (31,915,939 and 23,049,239 units outstanding
at December 31, 2001 and 2000, respectively) 408,562 217,073
Class B Common unitholders (1,307,190 units outstanding at each date) 19,534 21,042
Subordinated unitholders (10,029,619 units outstanding at each date) (38,891) (27,316)
General partner 13,592 3,200
---------------- ----------------
402,797 213,999
---------------- ----------------
$ 1,261,251 $ 885,801
================ ================
See notes to consolidated financial statements.
F-3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
Year Ended December 31,
---------------------------------------------------
2001 2000 1999
--------------- ---------------- ----------------
REVENUES $ 6,868,215 $ 6,641,187 $ 10,910,423
COST OF SALES AND OPERATIONS 6,720,970 6,506,504 10,800,109
UNAUTHORIZED TRADING LOSSES
AND RELATED EXPENSES (Note 3) - 6,963 166,440
INVENTORY VALUATION ADJUSTMENT (Note 2) 4,984 - -
--------------- ---------------- ----------------
Gross Margin 142,261 127,720 (56,126)
--------------- ---------------- ----------------
EXPENSES
General and administrative 46,586 40,821 23,211
Depreciation and amortization 24,307 24,523 17,344
Restructuring expense - - 1,410
--------------- ---------------- ----------------
Total expenses 70,893 65,344 41,965
--------------- ---------------- ----------------
OPERATING INCOME (LOSS) 71,368 62,376 (98,091)
Interest expense (29,082) (28,691) (21,139)
Gain on sale of assets (Note 5) 984 48,188 16,457
Interest and other income (expense) 401 10,776 958
--------------- ---------------- ----------------
Income (loss) before extraordinary item and
cumulative effect of accounting change 43,671 92,649 (101,815)
Extraordinary item (Note 10) - (15,147) (1,545)
Cumulative effect of accounting change (Note 9) 508 - -
--------------- ---------------- ----------------
NET INCOME (LOSS) $ 44,179 $ 77,502 $ (103,360)
=============== ================ ================
NET INCOME (LOSS) - LIMITED PARTNERS $ 42,239 $ 75,754 $ (101,517)
=============== ================ ================
NET INCOME (LOSS) - GENERAL PARTNER $ 1,940 $ 1,748 $ (1,843)
=============== ================ ================
BASIC AND DILUTED NET INCOME (LOSS)
PER LIMITED PARTNER UNIT
Income (loss) before extraordinary item and
cumulative effect of accounting change $ 1.12 $ 2.64 $ (3.16)
Extraordinary item - (0.44) (0.05)
Cumulative effect of accounting change 0.01 - -
--------------- ---------------- ----------------
Net income (loss) $ 1.13 $ 2.20 $ (3.21)
=============== ================ ================
WEIGHTED AVERAGE UNITS OUTSTANDING 37,528 34,386 31,633
=============== ================ ================
See notes to consolidated financial statements.
F-4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
----------------------------------------------
2001 2000 1999
--------------- -------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 44,179 $ 77,502 $ (103,360)
Items not affecting cash flows
from operating activities:
Depreciation and amortization 24,307 24,523 17,344
(Gain) loss on sale of assets (Note 5) (984) (48,188) (16,457)
Cumulative effect of accounting change (508) - -
Noncash compensation expense 5,741 3,089 1,013
Allowance for doubtful accounts 3,000 5,000 -
Inventory valuation adjustment 4,984 - -
Other non cash items (207) 4,574 1,047
Change in assets and liabilities, net of acquisition:
Accounts receivable and other (18,856) 120,497 (224,181)
Inventory (117,878) (11,954) 34,772
Accounts payable and other current liabilities 46,671 (161,543) 164,783
Pipeline linefill (13,736) (16,679) (3)
Other long-term liabilities and deferred credits 600 (8,591) 18,873
Due (to) from related party (7,266) (21,741) 34,924
--------------- -------------- -------------
Net cash provided by (used in) operating activities (29,953) (33,511) (71,245)
--------------- -------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions (Note 4) (229,162) - (176,918)
Additions to property and equipment (21,069) (12,603) (12,801)
Disposals of property and equipment and other (Note 5) 740 223,604 3,626
--------------- -------------- -------------
Net cash provided by (used in) investing activities (249,491) 211,001 (186,093)
--------------- -------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of units (Note 7) 227,549 - 76,450
Costs incurred in connection with financing arrangements (6,351) (6,748) (17,243)
Subordinated notes - general partner - (114,000) 114,000
Proceeds from long-term debt 1,837,750 1,433,750 403,721
Proceeds from short-term debt 492,005 51,300 131,119
Principal payments of long-term debt (1,803,073) (1,423,850) (268,621)
Principal payments of short-term debt (392,422) (108,719) (82,150)
Distributions to unitholders (75,929) (59,565) (51,673)
--------------- -------------- -------------
Net cash provided by (used in) financing activities 279,529 (227,832) 305,603
--------------- -------------- -------------
Net increase (decrease) in cash and cash equivalents 85 (50,342) 48,265
Cash and cash equivalents, beginning of period 3,426 53,768 5,503
--------------- -------------- -------------
Cash and cash equivalents, end of period $ 3,511 $ 3,426 $ 53,768
=============== ============== =============
See notes to consolidated financial statements.
F-5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(in thousands)
Total
Class B General Partners'
Common Units Common Units Subordinated Units Partner Capital
---------------------- ------------------- --------------------- ---------- ------------
Units Amount Units Amount Units Amount Amount Amount
--------- ------------ --------- --------- --------- ----------- ---------- ------------
Balance at December 31, 1998 20,059 $253,568 - $ - 10,030 $ 15,995 $ 980 $ 270,543
Issuance of Class B Common Units - - 1,307 25,000 - - 252 25,252
Noncash compensation expense - - - - - - 1,013 1,013
Issuance of units to public 2,990 50,654 - - - - 544 51,198
Net loss - (62,598) - (3,218) - (35,701) (1,843) (103,360)
Distributions - (33,265) - (1,234) - (15,915) (1,259) (51,673)
--------- ------------ --------- --------- --------- ----------- ---------- ------------
Balance at December 31, 1999 23,049 208,359 1,307 20,548 10,030 (35,621) (313) 192,973
Noncash compensation expense - - - - - - 3,089 3,089
Net income - 50,780 - 2,878 - 22,096 1,748 77,502
Distributions - (42,066) - (2,384) - (13,791) (1,324) (59,565)
--------- ------------ --------- --------- --------- ----------- ---------- ------------
Balance at December 31, 2000 23,049 217,073 1,307 21,042 10,030 (27,316) 3,200 213,999
Issuance of units 8,867 222,032 - - - - 5,517 227,549
Noncash compensation expense - - - - - - 5,741 5,741
Net income - 29,436 - 1,476 - 11,327 1,940 44,179
Distributions - (51,271) - (2,549) - (19,558) (2,551) (75,929)
Other comprehensive income - (8,708) - (435) - (3,344) (255) (12,742)
--------- ------------ --------- --------- --------- ----------- ---------- ------------
Balance at December 31, 2001 31,916 $ 408,562 1,307 $ 19,534 10,030 $ (38,891) $ 13,592 $ 402,797
========= ============ ========= ========= ========= =========== ========== ============
See notes to consolidated financial statements.
F-6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 -- Organization and Basis of Presentation
Organization
We are a publicly traded Delaware limited partnership engaged in interstate
and intrastate marketing, transportation and terminalling of crude oil and
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 affiliates ("Plains Resources") as a separate, publicly traded
master limited partnership.
We completed our initial public offering (IPO) in November 1998, issuing
13.1 million common units at $20.00 per unit and received net proceeds of $244.7
million. Concurrently with the offering, Plains Resources sold certain assets to
us and contributed other assets in exchange for cash, common and subordinated
units, an aggregate 2% general partner interest, the right to receive incentive
distributions as defined in the partnership agreement and the assumption of
related indebtedness. 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 of our general partner 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 was reduced
from 100% to 44%. Additionally, as a result of this transaction and various
equity offerings conducted since the IPO, Plains Resources' overall effective
ownership has been reduced to approximately 29%.
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.
We conduct our operations through our wholly owned operating limited
partnerships Plains Marketing, L.P., All American Pipeline, L.P., and Plains
Marketing Canada, L.P. Our operations are concentrated in Texas, Oklahoma,
California, Louisiana and the Canadian provinces of Alberta, Saskatchewan and
Manitoba.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our
consolidated financial position as of December 31, 2001 and 2000, and the
results of our operations, cash flows and changes in partners' capital for the
years ended December 31, 2001, 2000 and 1999. All significant intercompany
transactions have been eliminated. Certain reclassifications were made to prior
period amounts to conform with the current period presentation.
Note 2 -- Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Significant estimates we make include (1) estimated useful lives of assets,
which impacts depreciation and amortization, (2) allowance for doubtful accounts
receivable, (3) accruals related to revenues and expenses and (4) liability and
contingency accruals. Although we believe these estimates are reasonable, actual
results could differ from these estimates.
Revenue Recognition
Gathering and marketing revenues are accrued at the time title to the
product sold transfers to the purchaser, which occurs upon receipt of the
product by the purchaser. Terminalling and storage revenues are recognized at
the time service is performed. Revenues for the transportation of crude oil are
recognized either at the point of delivery or at the point of receipt pursuant
to regulated and non-regulated tariffs.
F-7
Cost of Sales and Operations
Cost of sales and operations consists of the cost of crude oil,
transportation and storage fees, field and pipeline operating expenses and
letter of credit expenses. Field and pipeline operating expenses consist
primarily of fuel and power costs, telecommunications, labor costs for truck
drivers and pipeline field personnel, maintenance, utilities, insurance and
property taxes.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested
in highly liquid instruments with original maturities of three months or less
and at times may exceed federally insured limits. We periodically assess the
financial condition of the institutions where these funds are held and believe
that any possible credit risk is minimal.
Accounts Receivable
Our accounts receivable are primarily from purchasers and shippers of crude
oil. The majority of our accounts receivable relate to our gathering and
marketing activities that can generally be described as high volume and low
margin activities, in many cases involving complex exchanges of crude oil
volumes. We make a determination of the amount, if any, of the line of credit to
be extended to any given customer and the form and amount of financial
performance assurances we require. Such financial assurances are commonly
provided in the form of standby letters of credit.
We routinely review our receivable balances to identify past due amounts
and analyze the reasons such amounts have not been collected. In many instances,
such delays involve billing delays and discrepancies or disputes as to the
appropriate price, volumes or quality of crude oil delivered or exchanged. We
also attempt to monitor changes in the creditworthiness of our customers as a
result of developments related to each customer, the industry as a whole and the
general economy. At December 31, 2001, approximately 93% of accounts receivable
were less than 60 days past scheduled invoice date. At December 31, 2001, our
allowance for doubtful accounts receivable totaled $3.0 million for receivables
included in current assets and $5.0 million for receivables classified as
long-term, representing 11% and 33%, respectively, of all balances greater than
60 days past scheduled invoice date. There was no allowance for doubtful
accounts at December 31, 1999. We consider these reserves adequate. Amounts due
from affiliated entities at December 31, 2001, totaled less than $0.6 million
and represented amounts due under current contracts in the ordinary course of
business or billings for reimbursing expenses that were collected subsequent to
year end. None of the accounts receivables are related to any equity investments
in the Partnership.
Inventory
Inventory consists of liquefied petroleum gas and crude oil in pipelines,
storage tanks and rail cars which is valued at the lower of cost or market, with
cost determined using an average cost method. In the fourth quarter of 2001, the
Partnership recorded a $5.0 million noncash writedown of operating crude oil
inventory to reflect prices at December 31, 2001. During 2001, the price of
crude oil traded on the NYMEX averaged $25.98 per barrel. At December 31, 2001,
the NYMEX crude oil price was approximately 24% lower, or $19.84 per barrel.
Property and Equipment and Pipeline Linefill
Property and equipment is stated at cost and consists of (in thousands):
December 31,
---------------------------
2001 2000
------------ -----------
Crude oil pipelines $ 470,671 $ 359,826
Crude oil pipeline facilities 87,446 39,358
Crude oil storage and terminal facilities 62,974 45,989
Trucking equipment, injection stations and other 25,599 19,435
Office property and equipment 6,360 3,011
------------ -----------
653,050 467,619
Less accumulated depreciation and amortization (48,131) (26,974)
------------ -----------
$ 604,919 $ 440,645
============ ===========
F-8
Depreciation is computed using the straight-line method over estimated
useful lives as follows:
. crude oil pipelines - 30 years;
. crude oil pipeline facilities - 30 years;
. crude oil storage and terminal facilities - 30 to 40 years;
. trucking equipment, injection stations and other - 5 to 15 years;
and
. office property and equipment - 5 years
Acquisitions and improvements are capitalized; maintenance and repairs are
expensed as incurred.
Pipeline linefill is recorded at cost and consists of liquefied petroleum
gas and crude oil linefill used to pack a pipeline such that when an incremental
barrel enters a pipeline it forces a barrel out at another location as well as
minimum crude oil necessary to operate our storage and terminalling facilities.
At December 31, 2001, we had approximately 2.6 million barrels of crude oil and
6.4 million gallons of liquefied petroleum gas used to maintain our minimum
operating linefill requirements. Proceeds from the sale and repurchase of
pipeline linefill are reflected as cash flows from operating activities in the
accompanying consolidated statements of cash flows.
Impairment of Long-Lived Assets
Long-lived assets with recorded values that are not expected to be
recovered through future cash flows are written-down to estimated fair value.
Fair value is generally determined from estimated discounted future net cash
flows.
Other Assets
Other assets consist of the following (in thousands):
December 31,
---------------------------
2001 2000
------------ ------------
Debt issue costs $ 17,293 $ 8,918
Long term receivable, net 10,000 5,000
Goodwill 9,419 601
Intangible assets (contracts) 980 -
Other 7,649 169
------------ ------------
45,341 14,688
Less accumulated amortization (4,458) (1,748)
------------ ------------
$ 40,883 $ 12,940
============ ============
Costs incurred in connection with the issuance of long-term debt are
capitalized and amortized using the straight-line method over the term of the
related debt. Use of the straight-line method does not differ materially from
the "effective interest" method of amortization. Goodwill is recorded as the
amount of the purchase price in excess of the fair value of certain assets
purchased. In accordance with Statement of Financial Accounting Standards (SFAS)
No. 142, "Goodwill and Other Intangible Assets", which we will adopt in its
entirety January 1, 2002, we will test goodwill and other intangible assets
periodically to determine whether an impairment has occurred. An impairment
occurs when the carrying amount of an asset exceeds the fair value of the
recognized goodwill or intangible asset. If impairment occurs, the loss is
recorded in the period.
Income and Other Taxes
No provision for U.S. federal or Canadian income taxes related to our
operations is included in the accompanying consolidated financial statements,
because as a partnership we are not subject to federal, state or provincial
income tax and the tax effect of our activities accrues to the unitholders. Net
earnings for financial statement purposes may differ significantly from taxable
income reportable to unitholders as a result of differences between the tax
bases and financial reporting bases of assets and liabilities and the taxable
income allocation requirements under the partnership agreement. Individual
unitholders will have different investment bases depending upon the timing and
price of acquisition of partnership units. Further, each unitholder's tax
accounting, which is partially dependent upon the unitholder's tax position, may
differ from the accounting followed in the consolidated financial statements.
Accordingly, there could be significant differences between each individual
unitholder's tax bases and the unitholder's share of the net assets reported in
the consolidated financial statements. We do not have access to information
about each individual unitholder's tax attributes, and the aggregate tax bases
cannot be readily determined. Accordingly, we do not believe that in our
circumstances, the aggregate difference would be meaningful information.
F-9
The Partnership's Canadian operations are conducted through an operating
limited partnership, of which our wholly owned subsidiary PMC (Nova Scotia)
Company is the general partner. For Canadian tax purposes, the general partner
is taxed as a corporation, subject to income taxes and a capital-based tax at
federal and provincial levels. For 2001, the income tax was not material and the
capital-based tax was approximately $0.4 million (U.S.). In addition, interest
payments made by Plains Marketing Canada, L.P. on its intercompany loan from
Plains Marketing, L.P. are subject to a 10% Canadian withholding tax, which for
2001 totaled $0.3 million and is recorded in other expense.
In addition to federal income taxes, owners of our common units may be
subject to other taxes, such as state and local and Canadian federal and
provincial taxes, unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various jurisdictions in which we do
business or own property. A unitholder may be required to file Canadian federal
income tax returns and to pay Canadian federal and provincial income taxes and
to file state income tax returns and to pay taxes in various states.
Hedging
We utilize various derivative instruments, for purposes other than trading,
to hedge our exposure to price fluctuations on crude oil and liquefied petroleum
gas in storage and expected purchases, sales and transportation of those
commodities. The derivative instruments consist primarily of futures and option
contracts traded on the New York Mercantile Exchange and over-the-counter
transactions including crude oil swap contracts entered into with financial
institutions. We also utilize interest rate and foreign exchange swaps and
collars to manage the interest rate exposure on our long-term debt and foreign
exchange exposure arising from our Canadian operations.
Beginning January 1, 2001, we record all derivative instruments on the
balance sheet as either assets or liabilities measured at their fair value under
the provisions of SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities". Generally for our domestic U.S. operations, these derivative
instruments qualify for hedge accounting as they reduce the price risk of the
underlying hedged item and are designated as a hedge at inception. These
derivative hedges result in financial impacts that are inversely correlated to
those of the items being hedged. This correlation, generally in excess of 80% (a
measure of hedge effectiveness), is measured both at the inception of the hedge
and on an ongoing basis. To qualify for hedge accounting treatment, companies
must formally document, designate and assess the effectiveness of these
transactions. If the necessary correlation ceases to exist or if physical
delivery of the hedged item becomes improbable, we would discontinue hedge
accounting and apply mark to market accounting. Gains and losses on the
termination of hedging instruments are deferred and recognized in income as the
impact of the hedged item is recorded.
SFAS 133 requires that changes in derivative contracts' fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. We have some derivative contracts, primarily related to our LPG activities,
that do not receive hedge treatment, as the correlation is not consistently at
the necessary level between prices for those markets or commodities and the
hedging instrument. As a result, gains and losses on those derivative contracts
impact earnings directly. The intent of entering into these transactions,
however, is to mitigate price exposure arising from those operations.
Aside from the exceptions noted above, unrealized changes in the market
value of crude oil or LPG hedge contracts are not generally recognized in our
consolidated statement of operations until the underlying hedged transaction
occurs. The financial impacts of these hedge contracts are included in our
consolidated statements of operations as a component of revenues. Such financial
impacts are offset by gains or losses realized in the physical market. Cash
flows from these hedging activities are included in operating activities in the
accompanying consolidated statements of cash flows. Net deferred gains and
losses on futures contracts (including closed futures contracts) entered into to
hedge anticipated crude oil and LPG purchases and sales, are included in current
assets or current liabilities in the accompanying consolidated balance sheets.
Deferred gains or losses from inventory hedges are included as part of the
inventory costs and recognized when the related inventory is sold.
Amounts paid or received from interest rate swaps and collars are charged
or credited to interest expense and matched with the cash flows and interest
expense of the debt being hedged, resulting in an adjustment to the effective
interest rate.
Net Income Per Unit
Basic and diluted net income (loss) per unit is determined by dividing net
income (loss) after deducting the amount allocated to the general partner
interest, (including its incentive distribution in excess of its 2% interest),
by the weighted average number of outstanding common units and subordinated
units. Partnership income (loss) is first allocated according to percentage
ownership in the Partnership and then reallocated between the limited partners
and general partner based on the amount of incentive distributions. Basic and
F-10
diluted net income (loss) per unit for 2001, 2000 and 1999 is as follows (in
thousands, except per unit data):
Year Ended December 31,
--------------------------------------------
2001 2000 1999
------------- ------------- -------------
Net income (loss) $ 44,179 $ 77,502 $ (103,360)
Less:
General partner incentive distributions (1,056) (198) (224)
General partner 2% ownership (884) (1,550) 2,067
------------- ------------- -------------
Net income (loss) attributable to
limited partners $ 42,239 $ 75,754 $ (101,517)
============= ============= =============
Weighted average units outstanding 37,528 34,386 31,633
============= ============= =============
Basic and diluted net income (loss)
per limited partner unit $ 1.13 $ 2.20 $ (3.21)
============= ============= =============
Foreign Currency Translation
Our cash flow stream relating to our Canadian operations is based on the
U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and
liabilities of our Canadian subsidiaries are translated to U. S. dollars using
the applicable exchange rate as of the end of a reporting period. Revenues and
expenses are translated using the average exchange rate during the reporting
period.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
141 "Business Combinations" and SFAS 142 "Goodwill and Other Intangible Assets".
SFAS 141 requires all business combinations initiated after June 30, 2001 (see
Note 4), to be accounted for under the purchase method. For all business
combinations for which the date of acquisition is after June 30, 2001, this
Standard also establishes specific criteria for the recognition of intangible
assets separately from goodwill. We have adopted SFAS 142 effective January 1,
2002. SFAS 142 changes the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years. In
conjunction with the adoption of SFAS 142, amortization on the unamortized
portion of the goodwill arising from previous acquisitions will cease in 2002.
The adoption of SFAS 142 will not have a material effect on either our financial
position, results of operations, or cash flows.
In June 2001, the FASB also issued SFAS 143, "Asset Retirement
Obligations". SFAS 143 establishes accounting requirements for retirement
obligations associated with tangible long-lived assets, including (1) the time
of the liability recognition, (2) initial measurement of the liability, (3)
allocation of asset retirement cost to expense, (4) subsequent measurement of
the liability and (5) financial statement disclosures. SFAS 143 requires that an
asset retirement cost should be capitalized as part of the cost of the related
long-lived asset and subsequently allocated to expense using a systematic and
rational method. We will adopt the statement effective January 1, 2003, as
required. The transition adjustment resulting from the adoption of SFAS 143 will
be reported as a cumulative effect of a change in accounting principle. At this
time, we cannot reasonably estimate the effect of the adoption of this statement
on either our financial position, results of operations, or cash flows.
In August 2001, the FASB approved SFAS 144, "Accounting for Impairment
or Disposal of Long-Lived Assets". SFAS 144 establishes a single accounting
model for long-lived assets to be disposed of by sale and provides additional
implementation guidance for assets to be held and used and assets to be disposed
of other than by sale. Upon adoption of this Statement effective January 1,
2002, there was no effect on either our financial position, results of
operations or cash flows.
In June 1998, the FASB issued SFAS 133, which was subsequently amended (i)
in June 1999 by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133", which
deferred the effective date of SFAS 133 to fiscal years beginning after June 15,
2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedge Activities," which amended certain provisions,
inclusive of the definition of the normal purchase and sale exclusion. We have
determined that our physical purchase and sale agreements qualify for the normal
purchase and sale exclusion.
SFAS 133 requires that all derivative instruments be recorded on the
balance sheet as either assets or liabilities measured at their fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other
F-11
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if so, the type of hedge transaction. For fair value
hedge transactions in which we are hedging changes in the fair value of an
asset, liability, or firm commitment, changes in the fair value of the
derivative instrument will generally be offset in the income statement by
changes in the fair value of the hedged item. For cash flow hedge transactions,
in which we are hedging the variability of cash flows related to a variable-rate
asset, liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income, a
component of partners' capital. The gains and losses on the derivative
instrument that are reported in other comprehensive income will be reclassified
as earnings in the periods in which earnings are affected by the variability of
the cash flows of the hedged item. The ineffective portion of all hedges will be
recognized in earnings in the current period. Hedge effectiveness is measured at
least quarterly based on the relative cumulative changes in fair value between
the derivative contract and the hedged item over time.
We adopted SFAS 133, as amended, effective January 1, 2001. Our
implementation procedures identified all instruments in place at the adoption
date that are subject to the requirements of SFAS 133. Upon adoption, we
recorded a cumulative effect charge of $8.3 million in accumulated other
comprehensive income to recognize at fair value all derivative instruments that
are designated as cash flow hedging instruments and a cumulative effect gain of
$0.5 million to earnings. Correspondingly, an asset of $2.8 million and a
liability of $10.6 million were established. Hedge losses/gains included in
accumulated other comprehensive income are transferred to earnings as the
forecasted transactions actually occur. Implementation issues continue to be
addressed by the FASB and any change to existing guidance might impact our
implementation. Adoption of this standard will most likely increase volatility
in earnings and partners' capital through comprehensive income.
Note 3 -- Unauthorized Trading Losses
In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated associated costs and legal
expenses). A full investigation into the unauthorized trading activities by
outside legal counsel and independent accountants and consultants determined
that the vast majority of the losses occurred from March through November 1999.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses (see
Note 14).
Note 4 -- Acquisitions
Wapella Pipeline System
In December 2001, we acquired the Wapella Pipeline System from private
investors for approximately $12.0 million, including transaction costs. The
system is 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 acquisition also
includes approximately 21,500 barrels of crude oil storage capacity located
along the system as well as a truck terminal. Initial financing for the
acquisition was provided through borrowings under our bank credit facility.
The Wapella acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with SFAS 141 (see
Note 2). The purchase price allocation is as follows (in thousands):
Crude oil pipeline, gathering and terminal assets $ 10,251
Other property and equipment 1,720
------------
Total $ 11,971
============
CANPET Energy Group Inc.
In July 2001, we acquired the assets of CANPET Energy Group Inc.
("CANPET"), a Calgary-based Canadian crude oil and liquefied petroleum gas
marketing company, for approximately $42.0 million plus excess inventory at the
closing date of approximately $25.0 million. 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 certain performance
standards, will be paid in common units in April 2004, if such standards are
met. At the time of the acquisition, CANPET's activities consisted of gathering
approximately 75,000 barrels per day of crude oil and marketing an average of
approximately 26,000 barrels per day of natural gas liquids or LPG's. 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. Initial financing for the
acquisition was provided through borrowings under our bank credit facility.
F-12
The CANPET acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with SFAS 141 (see
Note 2). The purchase price allocation is as follows (in thousands):
Inventory $ 29,708
Goodwill 8,818
Intangible assets (contracts) 980
Other assets, including debt issue costs 1,661
Pipeline linefill 4,332
Crude oil gathering and terminal assets 4,243
Other property and equipment 502
---------
Total $ 50,244
=========
Murphy Oil Company Ltd. Midstream Operations
In May 2001, we closed 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 ("the Murphy
Acquisition"), including financing and transaction costs. Initial financing for
the acquisition was provided through borrowings under our bank credit
facilities. The purchase included $6.5 million for excess inventory in the
pipeline systems. The principal assets acquired include approximately 450 miles
of crude oil and condensate transmission 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.
Murphy agreed to continue to transport production from fields previously
delivering crude oil to these pipeline systems, under a long-term contract. At
the time of the acquisition, the volume under the contract was approximately
11,000 barrels per day. Total volumes transported on the pipeline system in 2001
were approximately 223,000 barrels per day of light, medium and heavy crudes, as
well as condensate.
The Murphy Acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with Accounting
Principles Board Opinion No. 16, Business Combinations ("APB 16"). The purchase
price allocation, as adjusted pursuant to the provisions of the purchase and
sale agreement upon resolution of an outstanding pipeline tariff dispute, is as
follows (in thousands):
Crude oil pipeline, gathering and terminal assets $145,106
Pipeline linefill 7,602
Net working capital items 1,953
Other property and equipment 487
Other assets, including debt issue costs 360
--------
Total $155,508
========
F-13
Pro Forma Results for the Murphy and CANPET Acquisitions
The following unaudited pro forma data is presented to show pro forma
revenues, net income and basic and diluted net income per limited partner unit
for the Partnership as if the Murphy and CANPET acquisitions had occurred on
January 1, 2000 (in thousands):
Year Ended December 31,
-----------------------------
2001 (1) 2000 (1)
-------------- -------------
Revenues $ 7,043,143 $ 7,330,621
============== =============
Income before extraordinary item and cumulative
effective of accounting change $ 51,905 $ 98,821
============== =============
Net income $ 52,413 $ 83,674
============== =============
Basic and diluted income before extraordinary item and
cumulative effect of accounting change per
limited partner unit $ 1.32 $ 2.81
============== =============
Basic and diluted net income per limited partner unit $ 1.33 $ 2.38
============== =============
_________________
(1) The pro forma information does not include the results of the
Wapella acquisition as it would not differ materially from the
reported results.
Scurlock Acquisition
On May 12, 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 Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under a previous bank
facility;
. the sale to our former general partner of 1.3 million of our Class B
common units for a total cash consideration of $25.0 million, or
$19.125 per unit, the price equal to the market value of our common
units on May 12, 1999; and
. a $25.0 million draw under our revolving credit agreement.
The assets, liabilities and results of operations of Scurlock are included
in our consolidated financial statements effective May 1, 1999. The Scurlock
acquisition has been accounted for using the purchase method of accounting and
the purchase price was allocated in accordance with APB 16 as follows (in
thousands):
Crude oil pipeline, gathering and terminal assets $ 125,120
Other property and equipment 1,546
Pipeline linefill 16,057
Other assets (debt issue costs) 3,100
Other long-term liabilities (environmental accrual) (1,000)
Net working capital items (3,090)
-----------
Cash paid $ 141,733
===========
The purchase accounting entries include a $1.0 million accrual for
estimated environmental remediation costs. Under the agreement for the sale of
Scurlock by Marathon Ashland Petroleum, Marathon Ashland Petroleum has agreed to
indemnify us and hold us harmless for claims, liabilities and losses resulting
from any act or omission attributable to Scurlock's business or properties
occurring prior to the date of the closing of such sale to the extent the
aggregate amount of such losses exceed $1.0 million; provided, however, that
claims for such losses must individually exceed $25,000 and must be asserted by
us against Marathon Ashland Petroleum on or before May 15, 2003.
West Texas Gathering System Acquisition
On July 15, 1999, we completed the acquisition of a West Texas crude oil
pipeline and gathering system from Chevron Pipe Line Company for approximately
$36.0 million, including transaction costs. Our total acquisition cost was
approximately $38.9 million including costs to address certain issues identified
in the due diligence process. The principal assets acquired include
approximately 450 miles of crude oil transmission mainlines, approximately 400
miles of associated gathering and lateral lines and approximately 2.9 million
barrels of crude oil storage and terminalling capacity in Crane,
F-14
Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the
amounts paid at closing was provided by a draw under a previous credit facility.
Note 5 -- Asset Disposition
In December 2001, we sold excess communications equipment remaining from
the sale of the All American Pipeline discussed below and recognized a gain of
$1.0 million.
In March 2000, we sold to a unit of El Paso Corporation 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 the acquisition of the line from Goodyear 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.
Note 6 -- Debt
Short-term debt and current maturities of long-term debt consist of the
following (in thousands):
December 31,
--------------------------
2001 2000
------------ -----------
$200.0 million senior secured letter of credit and borrowing facility
bearing interest at a weighted average interest rate of 3.8% at
December 31, 2001, and 8.4% at December 31, 2000 $ 100,000 $ 1,300
Other 1,482 -
------------ -----------
101,482 1,300
Current portion of long-term debt 3,000 -
------------ -----------
Total short-term debt and current maturities of long-term debt $ 104,482 $ 1,300
============ ===========
Long-term debt consists of the following (in thousands):
December 31,
--------------------------
2001 2000
------------ -----------
$450.0 million senior secured domestic revolving credit facility, bearing
interest at a weighted average interest rate of 4.5% at
December 31, 2001, and 9.2% at December 31, 2000 $ 27,450 $ 320,000
$200.0 million senior secured term B loan, bearing interest at a weighted
average interest rate of 4.5% at December 31, 2001 200,000 -
$100.0 million senior secured term loan, bearing interest at a weighted
average interest rate of 4.4% at December 31, 2001 100,000 -
$30.0 million Canadian senior secured revolving credit facility, bearing
interest at a weighted average interest rate of 4.4% at
December 31, 2001 27,227 -
------------ -----------
354,677 320,000
Less current maturities (3,000) -
------------ -----------
Total long-term debt $ 351,677 $ 320,000
============ ===========
F-15
In September 2001, we amended and expanded our credit facilities to include
a six-year, $200.0 million term B loan. In connection with this amendment, we
reduced the revolving portion of the facilities by $50.0 million. Our credit
facilities currently consist of:
. a $780.0 million senior secured revolving credit and term loan
facility, which is secured by substantially all of our assets. The
facility consists of (i) a $450.0 million domestic revolving
facility (reflecting the $50 million reduction in such facility in
connection with the September amendment), with a $10.0 million
letter of credit sublimit, (ii) a $30.0 million Canadian revolving
facility (with a $5.0 million letter of credit sublimit), (iii) a
$100.0 million term loan and (iv) a $200.0 million term B loan. The
facility matures, (i) as to the aggregate $480.0 million domestic
and Canadian revolver portions, in April 2005, (ii) as to the
$100.0 million term portion, in May 2006, and, (iii) as to the
$200.0 million term B loan portion, September 2007. On the revolver
portions, no principal is scheduled for payment prior to maturity.
The $100.0 million term loan portion of this facility has four
scheduled annual payments of principal, commencing May 4, 2002, in
the respective amounts of 1%, 7%, 8% and 8% of the original term
principal amount, with the remaining principal balance scheduled
for payment on the stated maturity date of May 5, 2006. If any part
of the term portion is prepaid prior to its first anniversary, a 1%
premium will be due on that portion. The $200.0 million term B loan
has 1% payable yearly commencing on September 21, 2002, with the
remaining principal balance scheduled for payment on the stated
maturity date of September 26, 2007. The term B loan may be prepaid
without penalty. The revolving credit and term loan facility bears
interest at our option at either the base rate, as defined, plus an
applicable margin, or LIBOR plus an applicable margin, and further,
the Canadian revolver may effectively bear interest based upon
bankers' acceptance rates. We incur a commitment fee on the unused
portion of the revolver portion of this credit facility.
. a $200.0 million senior secured letter of credit and borrowing
facility, the purpose of which is to provide standby letters of
credit to support the purchase and exchange of crude oil and other
specified petroleum products for resale and borrowings to finance
crude oil inventory and other specified petroleum products that
have been hedged against future price risk. The letter of credit
facility is secured by substantially all of our assets and has a
sublimit for cash borrowings of $100.0 million to purchase crude
oil and other petroleum products that have been hedged against
future price risk and to fund margin requirements under NYMEX
contracts used to facilitate our hedging activities. The letter of
credit facility expires in April 2004. Aggregate availability under
the letter of credit facility for direct borrowings and letters of
credit is limited to a borrowing base that is determined monthly
based on certain of our current assets and current liabilities,
primarily inventory and accounts receivable and accounts payable
related to the purchase and sale of crude oil and other specified
petroleum products. We incur a commitment fee on the unused portion
of this facility.
Our credit facilities prohibit distributions on, or purchases or
redemptions of, units if any default or event of default is continuing. In
addition, the agreements contain various covenants limiting our ability to,
among other things:
. incur indebtedness;
. grant liens;
. sell assets;
. make investments;
. engage in transactions with affiliates;
. enter into certain contracts; and
. enter into a merger or consolidation.
Our credit facilities treat a change of control as an event of default and
also require us to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio which is not greater than 4.00 to 1;
. an interest coverage ratio which is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.70 to 1.0 prior to
December 31, 2002, and 0.65 to 1.0 thereafter.
A default under our credit facilities would permit the lenders to
accelerate the maturity of the outstanding debt and to foreclose on the assets
securing the credit facilities. As long as we are in compliance with our
commercial credit agreements, they do not restrict our ability to make
distributions of "available cash" as defined in our partnership agreement. We
are currently in compliance with the covenants contained in our credit
agreements.
F-16
The credit facilities provide that the Partnership may issue up to $400.0
million of senior unsecured debt that has a maturity date extending beyond the
maturity date of the credit facilities. If senior unsecured debt is issued, the
aggregate amount available under the $450.0 million U.S. revolving credit
facility will be reduced by an amount equal to (a) 40% of the face amount of the
senior unsecured debt if the aggregate amount of new debt issued is less than
$350.0 million, or (b) 50% of the face amount of the senior unsecured debt if
the aggregate amount of new debt issued is equal to or greater than $350.0
million; provided, however, in both cases, the amount of the revolver reduction
is decreased by $50.0 million.
In January 2002, we amended our credit facility to remove a condition
requiring us to obtain lender approval before making any acquisition greater
than $50.0 million to provide the Partnership with greater structuring
flexibility to finance larger acquisitions.
Maturities
The aggregate amount of maturities of all long-term indebtedness at
December 31, 2001, for the next five years is: 2002 - $3.0 million, 2003 - $9.0
million, 2004 - $10.0 million, 2005 - $64.7 million, 2006 and thereafter -$268.0
million.
Note 7 - Partners' Capital and Distributions
Partners' capital consists of (1) 33,223,129 common units, including
1,307,190 Class B common units, representing a 75.3% effective aggregate
ownership interest in the Partnership and its subsidiaries, (after giving affect
to the general partner interest), (2) 10,029,619 Subordinated units representing
a 22.7% effective aggregate ownership interest in the Partnership and its
subsidiaries limited partner interest (after giving affect to the general
partner interest) and (3) a 2% general partner interest.
In May 2001, we completed a public offering of 3,966,700 common units.
Total net cash proceeds from the offering, including our former general
partner's proportionate contribution, were approximately $100.7 million. In
addition, in October 2001, we completed a public offering of 4,900,000 common
units. Net cash proceeds from the offering, including our general partner's
proportionate contribution, were approximately $126.0 million. The net proceeds
were used to repay borrowings under our revolving credit facility, a portion of
which was used to finance our Canadian acquisitions.
We will distribute 100% of our available cash within 45 days after the end
of each quarter to unitholders of record and to our general partner. Available
cash is generally defined as all of our cash and cash equivalents on hand at the
end of each quarter less reserves established by our general partner for future
requirements. Distributions of available cash to holders of subordinated units
are subject to the prior rights of holders of common units to receive the
minimum quarterly distribution ("MQD") for each quarter during the subordination
period and to receive any arrearages in the distribution of the MQD on the
common units for the prior quarters during the subordination period. There were
no arrearages on common units at December 31, 2001. The MQD is $0.45 per unit
($1.80 per unit on an annual basis). Common units will not accrue arrearages
with respect to distributions for any quarter after the subordination period and
subordinated units will not accrue any arrearages with respect to distributions
for any quarter.
The subordination period (as defined in the partnership agreement) will end
if certain financial tests are met for three consecutive four-quarter periods
(the "testing period"), but not sooner than December 31, 2003. During the first
quarter after the end of the subordination period, all of the subordinated units
will convert into common units, and will participate pro rata with all other
common units in future distributions. Early conversion of a portion of the
subordinated units may occur if the testing period is satisfied before December
31, 2003. We have determined that the first four-quarter period of the testing
period was satisfied as of September 30, 2001. Although we cannot give assurance
in that regard, if we continue to meet the requirements, 25% of the subordinated
units will convert in the fourth quarter of 2003 and the remainder will convert
in the first quarter of 2004.
Our general partner is entitled to receive incentive distributions if the
amount we distribute with respect to any quarter exceeds levels specified in our
partnership agreement. Under the quarterly incentive distribution provisions,
generally the general partner is entitled to 15% of amounts we distribute in
excess of $0.450 per unit, 25% of the amounts we distribute in excess of $0.495
per unit and 50% of amounts we distribute in excess of $0.675 per unit. Cash
distributions for the first, second, third and fourth quarters of 2001 were
$0.4750, $0.5000, $0.5125 and $0.5125, respectively, per unit on our outstanding
common units, Class B units and subordinated units, representing an excess of
$0.025, $0.050, $0.0625 and $0.0625 per unit, respectively, over the MQD. Cash
distributions for the second, third and fourth quarters of 2000 were $0.4625 per
unit on our outstanding common units, Class B units and subordinated units,
representing an excess of $0.0125 per unit over the MQD. Cash distributions for
the second and third quarters of 1999 were $0.4625 and $0.4812 per unit,
respectively, on our outstanding common units, Class B units and subordinated
units, representing an excess of $0.0125 per unit and $0.0312 per unit,
respectively, over the MQD. Distributions were not paid on the subordinated
units for the fourth quarter of 1999.
F-17
The Class B common units are initially pari passu with common units with
respect to distributions, and are convertible into common units upon approval of
a majority of the common unitholders. The Class B unitholders may request that
we call a meeting of common unitholders to consider approval of the conversion
of Class B units into common units. If the approval of a conversion by the
common unitholders is not obtained within 120 days of a request, each Class B
common unitholder will be entitled to receive distributions, on a per unit
basis, equal to 110% of the amount of distributions paid on a common unit, with
such distribution right increasing to 115% if such approval is not secured
within 90 days after the end of the 120-day period. Except for the vote to
approve the conversion, Class B common units have the same voting rights as the
common units.
Note 8 -- Comprehensive Income
Comprehensive income includes net income and certain items recorded
directly to Partners' Capital and classified as Other Comprehensive Income
(OCI). Such amounts are allocated in proportion to the limited partners and
general partners interest. Following the adoption of SFAS 133, we recorded a
charge to OCI of $8.3 million related to the change in fair value of certain
derivative financial instruments that qualified for cash flow hedge accounting.
The following table reflects comprehensive income for the year ended
December 31, 2001 (in thousands):
Total comprehensive income at January 1, 2001 $ -
Cumulative effect of change in accounting principle (8,337)
Reclassification adjustment for settled contracts (2,526)
Changes in fair value of outstanding hedging positions 6,123
Currency translation adjustment (8,002)
-----------
Other comprehensive income (loss) (12,742)
Net income 44,179
-----------
Total comprehensive income at December 31, 2001 $ 31,437
===========
Note 9 -- Financial Instruments
Derivatives
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. In
accordance with the transition provisions of SFAS 133, we recorded a loss of
$8.3 million in OCI, representing the cumulative effect of an accounting change
to recognize, at fair value, all cash flow derivatives. We also recorded a
noncash gain of $0.5 million in earnings as a cumulative effect adjustment.
At December 31, 2001, a $4.7 million unrealized loss was recorded to OCI
together with related assets and liabilities of $4.2 million and $8.2 million,
respectively. Earnings included a noncash gain of $0.2 million (excluding the
$0.5 million gain related to the cumulative effect of accounting change upon
adoption of SFAS 133) related to the ineffective portion of our cash flow
hedges, as well as certain derivative contracts that did not qualify as hedges
primarily relating to our LPG activities due to a low correlation between the
futures contract and hedged item. Our hedge-related assets and liabilities are
included in other current assets and other current liabilities in the
consolidated balance sheet.
As of December 31, 2001, the total amount of deferred net losses on
derivative instruments recorded in OCI are expected to be reclassified to
earnings during 2002 and 2003. The following table sets forth our open crude oil
hedge positions at December 31, 2001. These are futures hedges and have
offsetting physical exposures to the extent they are effective.
2002 2003
------------------------------------------------ ---------------------------------------------
1st Qtr 2nd Qtr 3rd Qtr 4th Qtr 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr
------------ ------------ ------------ --------- --------- ------------ --------- ------------
Volume (bbls)
Short positions 1,228,000 - 200,000 - - 200,000 - 1,800,000
Long positions - 1,053,000 - - - - - -
Average price ($/bbl) $ 20.64 $ 22.73 $ 19.53 $ - $ - $ 21.26 $ - $ 21.23
Interest rate swaps and collars are used to hedge underlying interest
obligations. These instruments hedge interest rates on specific debt issuances
and qualify for hedge accounting. The interest rate differential is reflected as
an adjustment to interest expense over the life of the instruments. At December
31, 2001, we had interest rate swap and collar arrangements for an aggregate
notional principal amount of $275.0 million for which we would pay approximately
$5.3 million if such arrangements were terminated as of such date.
F-18
The table shown below summarizes the fair value of our interest rate swaps
and collars by year of maturity (in thousands):
Year of Maturity
------------------------------------------
2002 2003 2004 Total
-------- -------- ------- --------
Interest rate swaps $ -- $ (810) $ (689) $ (1,499)
Interest rate collars (3,777) -- -- (3,777)
-------- -------- -------- --------
Total $ (3,777) $ (810) $ (689) $ (5,276)
======== ======== ======== ========
The adjustment to interest expense resulting from interest rate swaps for
the years ended December 31, 2001, 2000 and 1999 was a $2.4 million loss, a $0.1
million gain and a $0.1 million loss, respectively. These instruments are based
on LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of 8.0%
with an expiration date of August 2002 for $125.0 million notional principal
amount. The fixed rate interest rate swaps provide for a rate of 4.3% for $50.0
million notional principal amount expiring March 2004, and a rate of 3.6% for
$100.0 million notional principal amount expiring September 2003.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured on a quarterly basis.
This process includes specific identification of the hedging instrument and the
hedge transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, we assess whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged items. No amounts were excluded from the computation of hedge
effectiveness.
Since substantially all of our Canadian business is conducted in Canadian
dollars (CAD), we use certain financial instruments to minimize the risks of
changes in the exchange rate. These instruments include forward exchange
contracts, forward extra option contracts and cross currency swaps.
Additionally, at December 31, 2001, $25.4 million ($40.5 million CAD) of our
long-term debt was denominated in Canadian dollars. All of the financial
instruments utilized are placed with large creditworthy financial institutions
and meet the criteria under SFAS 133 for hedge accounting treatment.
At December 31, 2001, we had forward exchange contracts and forward extra
option contracts that allow us to exchange $3.0 million Canadian for at least
$1.9 million U. S. (based on a Canadian-U.S. dollar exchange rate of 1.55)
quarterly during 2002 and 2003. If these contracts were terminated on December
31, 2001, we would receive $0.5 million U.S. At December 31, 2001, we also had a
cross currency swap contract for an aggregate notional principal amount of $25.0
million, effectively converting this amount of our $100.0 million senior secured
term loan (25% of the total) from U.S. dollars to $38.7 million of Canadian
dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms
of this contract mirror the term loan, matching the amortization schedule and
final maturity in May 2006. If this swap contract was terminated on
December 31, 2001, we would receive $0.5 million U.S.
The table shown below summarizes the fair value of our foreign currency
hedges by year of maturity (in thousands):
Year of Maturity
--------------------------------------
2002 2003 2006(1) Total
------ ------ ------- -------
Forward exchange contracts $ 123 $ 100 $ -- $ 223
Forward extra options 145 146 -- 291
Cross currency swaps -- -- 497 497
------ ------ ----- -------
Total $ 268 $ 246 $ 497 $ 1,011
====== ====== ===== =======
____________
(1) At December 31, 2001, we did not have foreign currency hedges
expiring in 2004 or 2005.
Fair Value of Financial Instruments
The carrying values of items comprising current assets and current
liabilities approximate fair value due to the short-term maturities of these
instruments. The carrying value of bank debt approximates fair value as interest
rates are variable, based on prevailing market rates. Crude oil futures
contracts permit settlement by delivery of the crude oil and, therefore, are not
F-19
financial instruments, as defined. The fair value of crude oil swap and option
contracts and interest rate swap and collar agreements are based on current
termination values or quoted market prices of comparable contracts.
The carrying amounts and fair values of our financial instruments are as
follows (in thousands):
December 31,
------------------------------------------------------
2001 2000
-------------------------- --------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ------------ ------------ ------------
Unrealized gain (loss) on interest rate
swaps and collars $ (5,276) $ (5,276) $ - $ (561)
Note 10 -- Early Extinguishment of Debt
During 2000, we recognized extraordinary losses, consisting primarily of
unamortized debt issue costs, totaling $15.1 million related to the permanent
reduction of the All American Pipeline, L.P. term loan facility and the
refinancing of our credit facilities. In addition, interest and other income for
the year ended December 31, 2000, included $9.7 million of previously deferred
gains from terminated interest rate swaps as a result of debt extinguishments
(see Note 3). The extraordinary loss of $1.5 million in 1999 relates to the
write-off of certain debt issue costs and penalties associated with the
prepayment of debt.
Note 11 -- Major Customers and Concentration of Credit Risk
Customers accounting for 10% or more of revenues were as follows for the
periods indicated:
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.
Financial instruments that potentially subject us to concentrations of
credit risk consist principally of trade receivables. Our accounts receivable
are primarily from purchasers and shippers of crude oil. This industry
concentration has the potential to impact our overall exposure to credit risk,
either positively or negatively, in that the customers may be similarly affected
by changes in economic, industry or other conditions. We review credit exposure
and financial information of our counterparties and generally require letters of
credit for receivables from customers that are not considered credit worthy,
unless the credit risk can otherwise be reduced.
Note 12 -- Related Party Transactions
Reimbursement of Expense of Our General Partner and Its Affiliates
We do not directly employ any persons to manage or operate our business.
These functions are provided by employees of our general partner. Our general
partner does not receive a management fee or other compensation in connection
with its management of us. We reimburse our general partner for all direct and
indirect costs of services provided, including the costs of employee, officer
and director compensation and benefits allocable to us, and all other expenses
necessary or appropriate to the conduct of our business, and allocable to us.
Our agreement provides that our general partner will determine the expenses
allocable to us in any reasonable manner determined by our general partner in
its sole discretion. Total costs reimbursed by us to our general partner in 2001
were approximately $31.3 million. Total costs reimbursed by us to our former
general partner and Plains Resources were approximately $31.2 million, $63.8
million and $44.7 million for the years ended December 31, 2001, 2000 and 1999,
respectively. Such costs include, (1) allocated personnel costs (such as
salaries and employee benefits) of the personnel providing such services, (2)
rent on office space allocated to our general partner in Plains Resources'
offices in Houston, Texas, (3) property and casualty insurance premiums and (4)
out-of-pocket expenses related to the provision of such services.
F-20
Crude Oil Marketing Agreement
We are the exclusive marketer/purchaser for all of Plains Resources' equity
crude oil production. The marketing agreement with Plains Resources provides
that we will purchase for resale at market prices all of Plains Resources' crude
oil production for which we charge a fee of $0.20 per barrel. This fee is
subject to adjustment every three years based on then-existing market
conditions. For the years ended December 31, 2001, 2000 and 1999, we paid Plains
Resources approximately $223.2 million, $244.9 million and $131.5 million,
respectively, for the purchase of crude oil under the agreement, including the
royalty share of production, and recognized margins of approximately $1.8
million, $1.7 million and $1.5 million from the marketing fee for the same
periods, respectively. In our opinion, these purchases were made at prevailing
market prices. In November 2001, the marketing agreement automatically extended
for an additional three-year period.
Separation Agreement
A separation agreement was entered into in connection with the General
Partner Transition pursuant to which (i) Plains Resources has indemnified us for
(a) claims relating to securities laws or regulations in connection with the
upstream or midstream businesses, based on alleged acts or omissions occurring
on or prior to June 8, 2001 or (b) claims related to the upstream business,
whenever arising, and (ii) we have indemnified Plains Resources for claims
related to the midstream business, whenever arising. Plains Resources also has
agreed to indemnify and maintain liability insurance for the individuals who
were, on or before June 8, 2001, directors or officers of Plains Resources or
our former general partner.
Financing
In May 2000, we repaid to our former general partner $114.0 million of
subordinated debt. Interest expense related to the notes was $3.3 million and
$0.6 million for the years ended December 31, 2000 and 1999, respectively.
To finance a portion of the purchase price of the Scurlock acquisition, we
sold to our former general partner 1.3 million Class B common units at $19.125
per unit, the market value of our common units on May 12, 1999 (see Note 4).
The balance of amounts due to related parties at December 31, 2001 and 2000
was $13.7 million and $21.0 million, respectively, and was related to crude oil
purchased by us but not yet paid as of December 31 of each year.
Transaction Grant Agreements
In connection with our initial public offering, our former general partner,
at no cost to us, agreed to transfer, subject to vesting, approximately 400,000
of its affiliates' common units (including distribution equivalent rights
attributable to such units) to certain key officers and employees of our former
general partner and its affiliates. Under these grants, the common units vested
based on attaining a targeted operating surplus for a given year. Of the 400,000
units subject to the transaction grant agreements, 69,444 units vested in 2000
for 1999's operating results and 133,336 units vested in 2001 for 2000's
operating results. The remainder (197,220 units) vested in connection with the
consummation of the General Partner Transition. Distribution equivalent rights
were paid in cash at the time of the vesting of the associated common units. The
values of the units and associated distribution equivalent rights that vested
under the Transaction Grant Agreements for all grantees in 2001, 2000 and 1999
were $5.7 million, $3.1 million and $1.0 million, respectively. Although we
recorded noncash compensation expenses with respect to these vestings, the
compensation expense incurred in connection with these grants was funded by our
former general partner, without reimbursement by us.
Performance Option Plan
In connection with the General Partner Transition, all except one of the
owners of the general partner contributed an aggregate of 450,000 subordinated
units to the general partner to provide a pool of units available for the grant
of options to management and key employees. In that regard, the general partner
adopted the Plains All American 2001 Performance Option Plan, pursuant to which
options to purchase approximately 332,500 units have been granted to officers
and key employees of our general partner. Such options vest in 25% increments
based upon achieving quarterly distribution levels on our units of $0.525,
$0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50 and $2.70, annualized). The
options will vest immediately upon a change in control (as defined in the grant
agreements). The purchase price under the options is $22 per subordinated unit,
declining over time in an amount equal to 80% of each quarterly distribution per
unit. The terms of future grants may differ from the existing grants. Because
the subordinated units underlying the plan were contributed to the general
partner, we will have no obligation to reimburse the general partner for the
cost of the units upon exercise of the options, but will have a noncash
compensation charge offset by a deemed capital contribution.
F-21
Stock Option Replacement
In connection with the General Partner Transition, certain members of the
management team that had been employed by Plains Resources were transferred to
the general partner. At that time, such individuals held in-the-money but
unvested stock options in Plains Resources, which were subject to forfeiture
because of the transfer of employment. Plains Resources, through its affiliates,
agreed to substitute a contingent grant of subordinated units with a value equal
to the discounted present value of the spread on the unvested options, with
distribution equivalent rights from the date of grant. The subordinated units
vest on the same schedule as the stock options would have vested. The general
partner will administer the vesting and delivery of the units under the grants.
Because the units necessary to satisfy the delivery requirements under the
grants will be provided by Plains Resources, we will have no obligation to
reimburse the general partner for the cost of such units.
Benefit Plan
A subsidiary of Plains Resources was, until June 8, 2001, our general
partner. On that date, such entity transferred the general partner interest to
Plains AAP, L.P. Effective July 1, 2001, Plains All American GP LLC (Plains
AAP, L.P.'s general partner), now maintains a 401(k) defined contribution plan
whereby it matches 100% of an employee's contribution (subject to certain
limitations in the plan). For the period July 1 through December 31, 2001,
defined contribution plan expense was approximately $1.1 million.
Prior to July 1, 2001, Plains Resources maintained a 401(k) defined
contribution plan whereby it matched 100% of an employee's contribution (subject
to certain limitations in the plan), with matching contributions being made 50%
in cash and 50% in common stock (the number of shares for the stock match being
based on the market value of the common stock at the time the shares were
granted). For the period January 1 through June 30, 2001, defined contribution
plan expense was $1.0 million. For the years ended December 31, 2000 and 1999,
defined contribution plan expense was approximately $1.0 million and $0.7
million, respectively.
Note 13 -- Long-Term Incentive Plans
Our general partner has adopted the Plains All American GP LLC 1998
Long-Term Incentive Plan for employees and directors of our general partner and
its affiliates who perform services for us. The Long-Term Incentive Plan
consists of two components, a restricted unit plan and a unit option plan. The
Long-Term Incentive Plan currently permits the grant of restricted units and
unit options covering an aggregate of 1,425,000 common units. The plan is
administered by the Compensation Committee of our general partner's board of
directors. Our general partner's board of directors in its discretion may
terminate the Long-Term Incentive Plan at any time with respect to any common
units for which a grant has not yet been made. Our general partner's board of
directors also has the right to alter or amend the Long-Term Incentive Plan or
any part of the plan from time to time, including increasing the number of
common units with respect to which awards may be granted; provided, however,
that no change in any outstanding grant may be made that would materially impair
the rights of the participant without the consent of such participant.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles
the grantee to receive a common unit upon the vesting of the phantom unit. As of
March 5, 2002, aggregate outstanding grants of approximately 679,000 restricted
units have been made to employees of our general partner. Grants made include
165,000 restricted units to executive officers as a group. Additional grants of
approximately 288,000 restricted units have been approved, with vesting in 25%
increments when the quarterly distribution reaches $0.525, $0.575 and $0.625
($2.10, $2.30 and $2.50 annualized), and the criteria for the remaining 25% is
yet to be determined. These grants include approximately 203,000 restricted
units to executive officers of the general partner. The Compensation Committee
of the general partner may, in the future, make additional grants under the plan
to employees and directors containing such terms as the Compensation Committee
shall determine. Restricted units granted to employees during the subordination
period, although additional vesting criteria may sometimes apply, will vest only
after, and in the same proportions as, the conversion of the subordinated units
to common units. Grants made to non-employee directors of our general partner
are eligible to vest prior to termination of the subordination period. In 2000,
the three non-employee directors of our former general partner were each granted
5,000 restricted units. These units vested in connection with the consummation
of the General Partner Transition.
If a grantee terminates employment or membership on the board for any
reason, the grantee's restricted units will be automatically forfeited unless,
and to the extent, the Compensation Committee provides otherwise. Common units
to be delivered upon the vesting of rights may be common units acquired by our
general partner in the open market or in private transactions, common units
already owned by our general partner, or any combination of the foregoing. Our
general partner will be entitled to reimbursement by us for the cost incurred in
acquiring common units. In addition, we may issue up to 975,000 common units to
satisfy delivery obligations under the grants, less any common units issued upon
exercise of unit options under the plan (see below). If we issue new common
units upon vesting of the restricted units, the total number of common units
outstanding will increase. Whether we satisfy vested units with purchases or by
new issuances, the vesting will result in a compensation charge to us. Following
the subordination period, the Compensation Committee, in its discretion, may
grant tandem distribution equivalent rights with respect to restricted units.
F-22
The subordination period (as defined in the partnership agreement) will end
if certain financial tests are met for three consecutive four-quarter periods
(the "testing period"), but no sooner than December 31, 2003 (see Note 7).
The issuance of the common units pursuant to the restricted unit plan is
primarily intended to serve as a means of incentive compensation for
performance. Therefore, no consideration will be paid to us by the plan
participants upon receipt of the common units.
Unit Option Plan. The Unit Option Plan currently permits the grant of
options covering common units. No grants have been made under the Unit Option
Plan to date. However, the Compensation Committee may, in the future, make
grants under the plan to employees and directors containing such terms as the
committee shall determine, provided that unit options have an exercise price
equal to the fair market value of the units on the date of grant. Unit options
granted during the subordination period will become exercisable automatically
upon, and in the same proportions as, the conversion of the subordinated units
to common units, unless a later vesting date is provided.
Upon exercise of a unit option, our general partner will deliver common
units acquired by it in the open market, or in private transactions, or use
common units already owned by our general partner, or any combination of the
foregoing. In addition, we may issue up to 975,000 common units to satisfy
delivery obligations under the grants less any common units issued upon vesting
of restricted units under the plan. Our general partner will be entitled to
reimbursement by us for the difference between the cost incurred by our general
partner in acquiring such common units and the proceeds received by our general
partner from an optionee at the time of exercise. Thus, the cost of the unit
options will be borne by us. If we issue new common units upon exercise of the
unit options, the total number of common units outstanding will increase, and
our general partner will remit to us the proceeds received by it from the
optionee upon exercise of the unit option.
Certain employees and officers of the general partner have received grants
of equity not associated with the Long-Term Incentive Plan described above, and
for which we have no cost or reimbursement obligations (see Note 12).
Note 14 -- Commitments and Contingencies
We lease certain real property, equipment and operating facilities under
various operating leases. We also incur costs associated with leased land,
rights-of-way, permits and regulatory fees, the contracts for which generally
extend beyond one year but can be cancelled at any time should they not be
required for operations. Future non-cancellable commitments related to these
items at December 31, 2001, are summarized below (in thousands):
2002 $ 6,774
2003 6,245
2004 6,340
2005 6,216
2006 4,458
Thereafter 5,595
Total lease expense incurred for 2001, 2000 and 1999 was $7.4 million, $6.7
million and $8.9 million, respectively. As is common within the industry and in
the ordinary course of business, we have also entered into various operational
commitments and agreements related to pipeline operations and to marketing,
transportation, terminalling and storage of crude oil and liquefied petroleum
gas.
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 that 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 $0.4 million to date in connection with this spill and do
not expect any additional expenditures to be material to the financial
statements, although we can provide no assurances in that regard.
F-23
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 proposed extending the scope
of our study and are awaiting the state's response. We have spent approximately
$0.1 million to date in investigating the contamination at this site. We do not
anticipate the total additional cost related to this site to exceed $0.3
million, although no assurance can be given that the actual cost could not
exceed such estimate.
Litigation
Texas Securities Litigation. On November 29, 1999, a class action lawsuit
was filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of our former general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
were filed in the Southern District of Texas, some of which named our former
general partner and Plains Resources as additional defendants. All of the
federal securities claims were consolidated into two actions. The first
consolidated action is that filed by purchasers of Plains Resources' common
stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al.
The second consolidated action is that filed by purchasers of our common units,
and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al.
Plaintiffs alleged that the defendants were liable for securities fraud
violations under Rule l0b-5 and Section 20(a) of the Securities Exchange Act of
1934 and for making false registration statements under Sections 11 and 15 of
the Securities Act of 1933.
We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
our former general partner and the board of directors of Plains Resources. All
such amounts were reflected in our financial statements at December 31, 2000.
The settlement was approved by the court on December 19, 2001. The order became
final on January 18, 2002. The settlement agreement does not affect the Texas
Derivative Litigation and Delaware Derivative Litigation described below.
Delaware Derivative Litigation. On December 3, 1999, two derivative
lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled
Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American
Inc., et al. These suits, and three others which were filed in Delaware
subsequently, named our former general partner, its directors and certain of its
officers as defendants, and allege that the defendants breached the fiduciary
duties that they owed to Plains All American Pipeline, L.P. and its unitholders
by failing to monitor properly the activities of its employees. The court
consolidated all of the cases under the caption In Re Plains All American Inc.
Shareholders Litigation, and has designated the complaint filed in Susser v.
Plains All American Inc. as the complaint in the consolidated action.
The plaintiffs in the Delaware derivative litigation seek, among other
things, to cause the defendants to account for all losses and damages allegedly
sustained by Plains All American from the unauthorized trading losses; to
establish and maintain effective internal controls ensuring that our affiliates
and persons responsible for our affairs do not engage in wrongful practices
detrimental to Plains All American; and to pay for the plaintiffs' costs and
expenses in the litigation, including reasonable attorneys' fees, accountants'
fees and experts' fees.
We have agreed with the plaintiffs to settle the Delaware litigation for
approximately $1.1 million. On March 6, 2002, the Delaware court approved the
settlement.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was
filed in the United States District Court of the Southern District of Texas
entitled Fernandes v. Plains All American Inc., et al, naming our former general
partner, its directors and certain of its officers as defendants. This lawsuit
contains the same claims and seeks the same relief as the Delaware derivative
litigation, described above. We have reached an agreement in principle with the
plaintiffs, subject to approval by the District Court, to settle the Texas
litigation for approximately $112,500.
Other. We, in the ordinary course of business, are a claimant and/or a
defendant in various other legal proceedings. We do not believe that the outcome
of these other legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
F-24
Note 15 -- Quarterly Financial Data (Unaudited) (in thousands, except per unit
data):
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------------- ------------- ------------- ------------- --------------
2001
----
Revenues $ 1,520,124 $ 1,586,617 $ 2,191,310 $ 1,570,164 $ 6,868,215
Gross margin 32,730 36,387 39,644 33,500 142,261
Operating income 19,071 14,843 22,945 14,509 71,368
Income before extraordinary item and
cumulative effect of accounting change 12,507 7,067 15,161 8,936 43,671
Cumulative effect of accounting change 508 - - - 508
Net income 13,015 7,067 15,161 8,936 44,179
Income per limited partner unit before
extraordinary item and cumulative
effect of accounting change (1) 0.36 0.19 0.38 0.20 1.12
Cumulative effect of accounting change 0.01 - - - 0.01
After extraordinary item (1) 0.37 0.19 0.38 0.20 1.13
Cash distributions per common unit (2) $ 0.475 $ 0.500 $ 0.513 $ 0.513 $ 2.000
2000
----
Revenues $ 2,002,507 $ 1,481,834 $ 1,555,863 $ 1,600,983 $ 6,641,187
Gross margin 36.552 32.774 25.960 32.434 127.720
Operating income 17,788 20,164 10,700 13,724 62,376
Income before extraordinary item and
cumulative effect of accounting change 64,300 17,063 4,516 6,770 92,649
Extraordinary item (4,145) (11,002) - - (15,147)
Net income 60,155 6,061 4,516 6,770 77,502
Income per limited partner unit before
extraordinary item and cumulative
effect of accounting change 1.83 0.49 0.13 0.19 2.64
Extraordinary item (0.12) (0.32) - - (0.44)
Net income per limited partner unit 1.71 0.17 0.13 0.19 2.20
Cash distributions per common unit (2) $ 0.450 $ 0.463 $ 0.463 $ 0.463 $ 1.839
_______________
(1) The sum of the four quarters does not equal the total year due to
rounding.
(2) Represents cash distributions declared per common unit for the period
indicated. Distributions are paid in the following calendar quarter.
Note 16 -- Operating Segments
Our operations consist of two operating segments: (1) Pipeline Operations -
engages in interstate and intrastate crude oil pipeline transportation and
certain related merchant activities; (2) Marketing, Gathering, Terminalling and
Storage Operations - engages in purchases and resales of crude oil and liquified
petroleum gas at various points along the distribution chain and the leasing of
certain terminalling and storage assets. We evaluate segment performance based
on gross margin, gross profit and income (loss) before extraordinary items and
cumulative effect of accounting change.
The following table summarizes segment revenues, gross margin, gross profit
and income (loss) before extraordinary items and cumulative effect of accounting
change (in thousands):
Marketing,
Gathering,
Terminalling
Pipeline & Storage Total
- -----------------------------------------------------------------------------------------------------------
Twelve Months Ended December 31, 2001
Revenues:
External Customers $ 339,852 $ 6,528,363 $ 6,868,215
Intersegment (a) 17,528 2,046 19,574
Other revenue 53 348 401
------------- ---------------- --------------
Total revenues of reportable segments $ 357,433 $ 6,530,757 $ 6,888,190
============= ================ ==============
Gain on sale of assets $ 984 $ - $ 984
Segment gross margin (b) 71,322 70,939 142,261
Segment gross profit (c) 65,110 36,306 101,416
Income allocated to reportable segments (d) 39,494 9,918 49,412
Noncash compensation expense n/a n/a 5,741
------------- ---------------- --------------
Income before extraordinary item and
cumulative effect of accounting change $ n/a $ n/a $ 43,671
============= ================ ==============
Interest expense 10,667 18,415 29,082
Depreciation and amortization 15,983 8,324 24,307
Capital expenditures 11,035 30,204 41,239
Total assets 472,324 788,927 1,261,251
- ----------------------------------------------------------------------------- -----------------------------
Table continued on following page
F-25
Marketing,
Gathering,
Terminalling
Pipeline & Storage Total
- -----------------------------------------------------------------------------------------------------------
Twelve Months Ended December 31, 2000
Revenues:
External Customers $ 505,712 $ 6,135,475 $ 6,641,187
Intersegment (a) 68,745 - 68,745
Other revenue 9,045 1,731 10,776
------------- ---------------- --------------
Total revenues of reportable segments $ 583,502 $ 6,137,206 $ 6,720,708
============= ================ ==============
Gain on sale of assets $ 48,188 $ - $ 48,188
Segment gross margin (b) 51,787 75,933 127,720
Segment gross profit (c) 49,996 39,992 89,988
Income allocated to reportable segments (d) 94,461 1,277 95,738
Noncash compensation expense n/a n/a 3,089
------------- ---------------- --------------
Income before extraordinary item and
cumulative effect of accounting change $ n/a $ n/a $ 92,649
============= ================ ==============
Interest expense 5,738 22,953 28,691
Depreciation and amortization 7,030 17,493 24,523
Capital expenditures 1,544 11,059 12,603
Total assets 324,751 561,050 885,801
- ----------------------------------------------------------------------------- -----------------------------
Twelve Months Ended December 31, 1999
Revenues:
External Customers $ 854,377 $ 10,056,046 $ 10,910,423
Intersegment (a) 131,445 - 131,445
Other revenue 195 763 958
------------- ---------------- --------------
Total revenues of reportable segments $ 986,017 $ 10,056,809 $ 11,042,826
============= ================ ==============
Segment gross margin (b) $ 58,001 $ (114,127) $ (56,126)
Segment gross profit (c) 55,384 (133,708) (78,324)
Income (loss) allocated to reportable segments (d) 46,075 (146,877) (100,802)
Noncash compensation expense n/a n/a 1,013
------------- ---------------- --------------
Income (loss) before extraordinary item and
cumulative effect of accounting change $ n/a $ n/a $ (101,815)
============= ================ ==============
Interest expense 13,572 7,567 21,139
Depreciation and amortization 10,979 6,365 17,344
Capital expenditures 69,375 119,911 189,286
Total assets 524,438 698,599 1,223,037
- -----------------------------------------------------------------------------------------------------------
(a) Intersegment sales were conducted on an arm's length basis.
(b) Gross margin is calculated as revenues less cost of sales and
operations expense. The 2001 gross margin includes the impact of the
$5.0 million inventory valuation adjustment.
(c) Gross profit is calculated as revenues less costs of sales and
operations expenses and general and administrative expenses, excluding
noncash compensation expense.
(d) Excludes noncash compensation expense, as it is not allocated to the
reportable segments.
F-26
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 Note
4). 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
Note 17 -- Subsequent Events
Acquisitions
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 transaction 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.
In February 2002, we acquired an approximate 22% equity interest in Butte
Pipe Line Company from Murphy Ventures, a 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 that runs from Baker, Montana, to Guernsey, Wyoming.
The Butte Pipeline System, principally a mainline system, transported
approximately 60,000 barrels per day of crude oil at the time of acquisition.
The remaining 78% interest in the Butte Pipe Line Company is owned by Equilon
Pipeline Company LLC.
F-27