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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K/A
Amendment No. 1
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
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.)
500 Dallas Street
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 654-1414
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Title of each class Name of each exchange on which registered
------------------------ ---------------------------------------------
Common Units New York Stock Exchange
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 [_]
The aggregate value of the Common Units held by non-affiliates of the registrant
(treating all executive officers and directors of the registrant, for this
purpose, as if they may be affiliates of the registrant) was approximately
$375,808,346 on March 22, 2000, based on $16 3/8 per unit, the closing price of
the Common Units as reported on the New York Stock Exchange on such date.
At March 22, 2000, there were outstanding 23,049,239 Common Units, 1,307,190
Class B Common Units and 10,029,619 Subordinated Units.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [x]
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
1999 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PAGE
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Part I
Items 1. and 2. Business and Properties.................................. 3
Item 3. Legal Proceedings........................................ 21
Item 4. Submission of Matters to a Vote of Security Holders...... 21
PART II
Item 5. Market for Registrant's Common Units and Related
Unitholder Matters....................................... 22
Item 6. Selected Financial and Operating Data.................... 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 25
Item 7a. Quantitative and Qualitative Disclosures About
Market Risks............................................. 37
Item 8. Financial Statements and Supplementary Data.............. 37
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................... 37
PART III
Item 10. Directors and Executive Officers of
Our General Partner...................................... 38
Item 11. Executive Compensation................................... 40
Item 12. Security Ownership of Certain Beneficial Owners
and Management........................................... 43
Item 13. Certain Relationships and Related Transactions........... 43
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 46
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. These statements, however, are subject to certain risks,
uncertainties and assumptions, including, but not limited to:
. the availability of adequate supplies of and demand for crude oil in the
areas in which we operate;
. the impact of crude oil price fluctuations;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. the impact of current and future laws and governmental regulations;
. environmental liabilities that are not covered by an indemnity or
insurance; and
. general economic, market or business conditions.
If one or more of these risks or uncertainties materialize, or if underlying
assumptions prove incorrect, actual results may vary materially from the results
anticipated in the forward-looking statements. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
We are a publicly traded Delaware limited partnership engaged in interstate
and intrastate marketing, transportation and terminalling of crude oil.
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". We were formed in September 1998 to acquire and operate the
midstream crude oil business and assets of Plains Resources Inc., whose wholly-
owned subsidiary, Plains All American, Inc., is our general partner. In 1999, we
grew through acquisitions and internal development to become one of the largest
transporters, terminal operators, gatherers and marketers of crude oil in the
United States. At the beginning of 2000, we handled an average of approximately
650,000 barrels of crude oil per day.
Our operations are concentrated in California, Texas, Oklahoma, Louisiana and
the Gulf of Mexico and can be categorized into two primary business activities:
. CRUDE OIL PIPELINE TRANSPORTATION. Our activities from pipeline operations
generally consist of transporting third-party volumes of crude oil for a
tariff, as well as merchant activities designed to capture location and
quality price differentials. We own and operate several pipeline systems
including:
. a segment of the All American Pipeline that extends approximately 140
miles from Las Flores, California to Emidio, California. In March 2000,
we sold the 1,089-mile segment of the All American Pipeline that extends
from Emidio, California to McCamey, Texas. See "All American Pipeline
Linefill Sale and Asset Disposition";
. the San Joaquin Valley Gathering System in California;
. the West Texas Gathering System, the Spraberry Pipeline System, and the
East Texas Pipeline System, which are all located in Texas;
. the Sabine Pass Pipeline System in southwest Louisiana and southeast
Texas;
. the Ferriday Pipeline System in eastern Louisiana and western
Mississippi; and
. the Illinois Basin Pipeline System in southern Illinois.
. TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES
We own and operate a state-of-the- art, 3.1 million barrel, above-ground
crude oil terminalling and storage facility at Cushing, Oklahoma, the
largest crude oil trading hub in the United States and the designated
delivery point for New York Mercantile Exchange ("NYMEX") crude oil futures
contracts. We also have an additional 6.6 million barrels of terminalling
and storage capacity in our other facilities, including tankage associated
with our pipeline and gathering systems. Our terminalling and storage
operations increase our margins in our business of purchasing and selling
crude oil and also generate revenue through a combination of storage and
throughput charges to third parties.
We own or lease approximately 280 trucks, 325 tractor-trailers and 290
injection stations, which we use in our gathering and marketing activities.
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; and
. the subsequent resale or exchange of crude oil at various points along
the crude oil distribution chain.
PARTNERSHIP STRUCTURE AND MANAGEMENT
Our operations are conducted through, and our operating assets are owned by,
our subsidiaries. We own our interests in our subsidiaries through three
operating partnerships, Plains Marketing, L.P., All American Pipeline, L.P. and
Plains Scurlock Permian, L.P.
Our general partner has sole responsibility for conducting our business and
managing our operations and owns all of the incentive distribution rights. Some
of the senior executives who currently manage our business also manage and
operate the business of Plains Resources. 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.
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The chart below depicts the organization and ownership of Plains All American
Pipeline, the operating partnerships and the subsidiaries as of December 31,
1999. As is reflected in the chart, a subsidiary of our general partner owns
6,904,795 common units and 10,029,619 subordinated units, representing a 19.7%
and 28.6% interest in the partnership and our subsidiaries. In addition, our
general partner owns 1,307,190 Class B common units representing a 3.7% interest
in the partnership and our subsidiaries. The percentages reflected in the
organization chart represent the approximate ownership interest in Plains All
American Pipeline, the operating partnerships and their subsidiaries
individually and not on a combined basis.
[CHART APPEARS HERE]
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UNAUTHORIZED TRADING LOSSES
Background
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,
and the impact warranted a restatement of previously reported financial
information for 1999 and 1998 (see Note 3 in the Notes to the Consolidated and
Combined Financial Statements appearing elsewhere in this report).
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 authorized 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 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.
The new policy was adopted by the Board of Directors of Plains All American
Inc. in May 2000; however, implementation of many of the procedures commenced in
January 2000, based on information developed throughout the investigation and
the review of the policies, processes and procedures. In March 2000, management
hired another independent accounting firm to provide additional objective input
regarding the processes and procedures, and to supplement management's efforts
to expedite the implementation of the enhanced policies and automation of the
processes and procedures. The procedures have now been implemented, although not
all reports are fully automated. The procedures have been, and will continue to
be, refined.
To specifically address the methods used by the trader to conceal the
authorized 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 trading strategies and risk tolerance to our
traders by more clearly and specifically defining those strategies and risk
limits in our written procedures.
. The new procedures require (i) more comprehensive and frequent reporting
that will allow our officials 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 (a new, independent function that reports directly to the
Chief Financial Officer) directly or 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 credit facilities and significant short-term cash
and letter of credit requirements. See Item 7. - "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources."
In December 1999, we executed amended credit facilities and obtained default
waivers from all of our lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit
facilities;
. increased availability under our letter of credit and borrowing facility
from $175.0 million in November 1999 to $295.0 million in December 1999,
$315.0 million in January 2000, and thereafter decreasing to $239.0 million
in February through April 2000, to $225.0 million in May and June 2000 and
to $200.0 million in July 2000 through July 2001;
. required the lenders' consent prior to the payment of distributions to
unitholders;
. prohibited contango inventory transactions subsequent to January 20, 2000;
and
. increased interest rates and fees under certain of the facilities.
We paid approximately $13.7 million to our lenders in connection with the
amended credit facilities. This amount was capitalized as debt issue costs and
will be amortized over the remaining term of the amended facilities. In
connection with the amendments, our general partner loaned us approximately
$114.0 million. This subordinated debt is due not later than November 30, 2005.
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 the amended 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, certain of our purchase contracts were terminated. As a
result of these changes, aggregate volumes purchased are expected to decrease by
150,000 barrels per day, consisting primarily of lower unit margin purchases.
Approximately 50,000 barrels per day of the decrease is related to barrels
gathered at producer lease locations and 100,000 barrels per day is attributable
to bulk purchases. As a result of the increase in letter of credit costs and
reduced volumes, annual Adjusted EBITDA is expected to be adversely affected by
approximately $5.0 million, excluding the positive impact of current favorable
market conditions. Adjusted EBITDA means earnings before interest expense,
income taxes, depreciation and amortization, unauthorized trading losses,
noncash compensation expense, restructuring expense, linefill gain and
extraordinary loss from extinguishment of debt.
RESULTS OF OPERATIONS
For the year ended December 31, 1999, our gross margin deficit, Adjusted
EBITDA, cash flow from operations and net loss totaled ($56.1) million, $89.1
million, $67.2 million and ($103.4) million, respectively. Excluding the
unauthorized trading losses, our gross margin and net income for the year ended
December 31, 1999 would have been $110.3 million and $63.1 million,
respectively. Cash flow from operations represents net income before noncash
items. Cash flow from operations also excludes the unauthorized trading losses,
noncash compensation expense, restructuring expense, linefill gain
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and extraordinary loss from extinguishment of debt. Excluding the unauthorized
trading losses, our pipeline operations accounted for approximately 53% of our
gross margin for year ended December 31, 1999, while our terminalling and
storage activities and gathering and marketing activities accounted for
approximately 47%.
ACQUISITIONS AND DISPOSITIONS
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.
Scurlock, previously a wholly-owned subsidiary of Marathon Ashland Petroleum,
is engaged in crude oil transportation, gathering and marketing, and owns
approximately 2,300 miles of active pipelines, numerous storage terminals and a
fleet of more than 250 trucks. Its largest asset is an 800-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.
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's limited
recourse bank facility with BankBoston, N.A.;
. the sale to our 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 existing revolving credit agreement.
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.
West Texas Gathering System Acquisition
On July 15, 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 the term loan portion of the Plains Scurlock credit facility. The
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 tankage located along the system.
All American Pipeline Linefill Sale and Asset Disposition
We initiated the sale of approximately 5.2 million barrels of crude oil
linefill from the All American Pipeline in November 1999. This sale was
substantially completed in February 2000. The linefill was located in the
segment of the All American Pipeline that extends from Emidio, California, to
McCamey, Texas. Except for minor third party volumes, Plains Marketing, L.P.,
one of our subsidiaries, has 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. Proceeds from the sale of the linefill were approximately
$100.0 million, net of associated costs, and were used for working capital
purposes. We estimate that we will recognize a total gain of approximately $44.6
million in connection with the sale of linefill. As of December 31, 1999, we had
delivered approximately 1.8 million barrels of linefill and recognized a gain of
$16.5 million.
On March 24, 2000, we completed the sale of the above referenced segment of
the All American Pipeline to a unit of El Paso Energy Corporation for total
proceeds of $129.0 million. The proceeds from the sale were used to reduce
outstanding debt. Our net proceeds are expected to be approximately $124.0
million, net of associated transaction costs and estimated costs to remove
certain equipment. We estimate that we will recognize a gain of approximately
$20.0 million in connection
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with the sale. During 1999, we reported gross margin of approximately $5.0
million from volumes transported on the segment of the line that was sold.
CRUDE OIL PIPELINE OPERATIONS
We present below a description of 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 provides us the ability to efficiently
batch differing crude oil types with varying characteristics through the
pipeline systems. The systems are designed to enhance leak detection
capabilities, sound automatic alarms in the event of operational conditions
outside of pre-established parameters and 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,
microwave, 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 anode bed based or
impressed current 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.
All American Pipeline
The segment of the All American Pipeline which was not sold to El Paso
(see "- All American Pipeline Linefill Sale and Asset Disposition") is a common
carrier crude oil pipeline system that transports crude oil produced from fields
offshore California to locations in California pursuant 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. The All American Pipeline
transports crude oil for third parties as well as for us.
We currently operate the segment of the system that extends approximately 10
miles from Exxon'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 SJV Gathering System as well as
various third party intrastate pipelines, including the Unocap Pipeline System,
Pacific Pipeline, and a pipeline owned by EOTT Energy Partners, L.P.
System Supply. The All American Pipeline currently transports Outer
Continental Shelf 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.
Effective December 1, 1999, the segment of the All American Pipeline that was
sold to El Paso ceased being used for crude oil transportation. Exxon, 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 segment of the All American
Pipeline which we retained. These agreements, which expire in August 2007,
provide for a minimum tariff with annual escalations. At December 31, 1999, the
tariffs averaged $1.41 per barrel for deliveries to connecting pipelines in
California. The agreements do not require these owners to transport a minimum
volume. The producers from the Point Arguello field who do not have contracts
with us have no other means of transporting their production and, therefore,
ship their volumes on the All American Pipeline at the posted tariffs. For the
year ended December 31, 1999, approximately $30.6 million, or 17%, of our gross
margin was attributable to the Santa Ynez field and approximately $10.6 million,
or 6% was attributable to the Point Arguello field. Transportation of volumes
from the Point Arguello field on the All American Pipeline commenced in 1991 and
from the Santa Ynez field in 1994.
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The table below sets forth the historical volumes received from both of these
fields.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------
1999 1998 1997 1996 1995 1994 1993 1992 1991
------- ------ ------ ------- ------ ------ ------- ------- ------
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes received from:
Point Arguello (at Gaviota) 20 26 30 41 60 73 63 47 29
Santa Ynez (at Las Flores) 59 68 85 95 92 34 - - -
------- ------ ------ ------- ------ ------ ------- ------- ------
Total 79 94 115 136 152 107 63 47 29
======= ====== ====== ======= ====== ====== ======= ======= ======
</TABLE>
In July 1999, a wholly-owned subsidiary of Plains Resources acquired Chevron
USA's 26% working interest in Point Arguello and 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. Plains Resources
expects that there will continue to be natural production declines from each of
these fields as the underlying reservoirs are depleted. As operator of Point
Arguello, Plains Resources is conducting additional drilling and other
activities on this field, but we cannot assure you that these activities will
affect the production decline.
San Joaquin Valley Supply. The San Joaquin Valley is one of the most prolific
oil producing regions in the continental United States, producing approximately
559,000 barrels per day of crude oil during the first nine months of 1999 that
accounted for approximately 67% of total California production and 11% of the
total production in the lower 48 states.
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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.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------------------
1999/(1)/ 1998 1997 1996 1995 1994 1993 1992 1991 1990
------- ------ ------ ------ ------- ------ ------ ------- ------- ------
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes:
San Joaquin Valley production (2) 559 592 584 579 569 578 588 609 634 629
Total California production
(excluding OCS volumes) 731 781 781 772 764 784 803 835 875 879
</TABLE>
----------------
(1) Reflects information through September 1999.
(2) Consists of production from California Division of Oil and Gas District IV.
System Demand. Deliveries from the All American Pipeline are made to
California refineries through connections with third-party pipelines at Sisquoc,
Pentland and Emidio. Deliveries at Mojave were discontinued in the second
quarter of 1999, and volumes previously delivered to Mojave are delivered to
Emidio. Except for the purging of linefill volumes, deliveries to Texas were
discontinued effective December 1, 1999.
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------
1999 1998 1997 1996 1995
-------- ------- -------- -------- -------
(barrels in thousands)
<S> <C> <C> <C> <C> <C>
Average daily volumes delivered to:
California
Sisquoc 27 24 21 17 11
Pentland 52 69 74 71 65
Mojave 7 22 32 6 -
Emidio 15 - - - -
-------- ------- -------- -------- -------
Total California 101 115 127 94 76
Texas (1) 56 59 68 113 141
-------- ------- -------- -------- -------
Total 157 174 195 207 217
======== ======= ======== ======== =======
</TABLE>
--------------
(1) See "Acquisitions and Dispositions - All American Pipeline Linefill and
Asset Disposition".
SJV Gathering System
The SJV Gathering System is a proprietary pipeline system. 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 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. In 1999, we leased a pipeline that provides us access to
the Lost Hills field. The SJV Gathering System also includes approximately
586,000 barrels of tank capacity, which can be used to facilitate movements
along the system as well as to support our other activities.
The SJV Gathering System is supplied with the crude oil production primarily
from major oil companies' equity production from the South Belridge, Cymeric,
Midway Sunset, Elk Hills and Lost Hills fields. The table below sets forth the
historical volumes received into the SJV Gathering System.
YEARS ENDED DECEMBER 31,
------------------------------------------
1999 1998 1997 1996 1995
------ ------ ------ ------ ------
(BARRELS IN THOUSANDS)
Total average daily volumes 84 85 91 67 50
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West Texas Gathering System
We purchased the West Texas Gathering System from Chevron Pipe Line Company in
July 1999 for approximately $36.0 million, including transaction costs. 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. In aggregate, these counties have produced on average in excess of
150,000 barrels per day of crude oil over the last four years. 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.
Lease volumes gathered into the system are approximately 50,000 barrels per
day. 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 44% of
total system gathering volumes and 22% of the total system volumes). Other large
producers connected to the gathering system include Burlington, Devon, Anadarko,
Altura, Bass, and Fina. Volumes from connecting carriers, including Exxon,
Phillips and Unocal, average approximately 42,000 barrels per day. Our West
Texas Gathering System has the capability to transport approximately 190,000
barrels per day. At the time of the acquistion, truck injection stations were
limited and provided less than 1,000 barrels per day. We have installed ten
truck injection stations on the West Texas Gathering System since the
acquisition. 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 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. Volumes received from truck injection stations
were increased to 10,000 barrels per day by the fourth quarter of 1999. The West
Texas Gathering System also includes approximately 2.9 million barrels of tank
capacity located along the pipeline system.
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 800 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 gathers approximately 34,000 barrels per day of crude oil. Large
suppliers to the Spraberry Pipeline System include Lantern Petroleum and Pioneer
Natural Resources. The Spraberry Pipeline System also includes approximately
173,000 barrels of tank capacity located along the pipeline.
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 6 inches in
diameter and has a throughput capacity of approximately 26,000 barrels of
Louisiana light sweet crude oil per day. For the year ended December 31, 1999,
the system transported approximately 16,500 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 which is located in East Louisiana and
West Mississippi. The Ferriday Pipeline System consists of approximately 600
miles of pipe ranging from 2 inches to 12 inches in diameter. The Ferriday
Pipeline System delivers 9,000 barrels per day of crude oil to third-party
pipelines that supply refiners in the Midwest. The Ferriday Pipeline System also
includes approximately 348,000 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
West Mississippi with the portion of the system located in East 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.
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East Texas Pipeline System
The East Texas Pipeline System, acquired in the Scurlock acquisition, is a
proprietary crude oil pipeline system that is used to gather approximately
10,000 barrels per day of crude oil in East Texas and transport approximately
22,000 barrels per day of crude oil to Crown Central's refinery in Longview,
Texas. The deliveries to Crown Central are subject to a five-year 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.
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 170 miles of pipe of varying diameter and delivers approximately
6,400 barrels per day of crude oil to third-party pipelines that supply refiners
in the Midwest. Approximately 3,600 barrels per day of the supply on this system
are from fields operated by Plains Resources.
TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES
Terminalling and Storage Activities
We own approximately 9.7 million barrels of terminalling and storage assets,
including tankage associated with our pipeline and gathering systems. Our
storage and terminalling operations increase our margins in our business of
purchasing and selling crude oil and also generate revenue through a combination
of storage throughput changes to 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 such 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 or when the market switches from contango
to backwardation.
Our most significant terminalling and storage asset is our Cushing Terminal
which was constructed in 1993, and expanded by approximately 50% 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.
The Cushing Terminal has total storage capacity of approximately 3.1 million
barrels. The Cushing Terminal is comprised of fourteen 100,000 barrel tanks,
four 150,000 barrel tanks and four 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 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. In order to service an expected increase in
the volumes as well as the varieties of foreign and domestic crude oil projected
to be transported through the Cushing Interchange, we incorporated certain
attributes into the design of the Cushing Terminal including:
. 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;
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. 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 to handle an 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 and secondary seals. The Cushing Terminal is
the only terminal at the Cushing Interchange equipped with aboveground
pipelines. Like the pipeline systems we operate, the Cushing Terminal is
operated by a computer system designed to monitor real time operational data and
each tank is cathodically protected. In addition, each tank is equipped with an
audible and visual high level alarm system to prevent overflows; a double seal
floating roof that minimizes air emissions and prevents 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 light sweet 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 1995
through 1999.
YEAR ENDED DECEMBER 31,
---------------------------------
1999 1998 1997 1996 1995
----- ----- ----- ----- -----
(BARRELS IN THOUSANDS)
Throughput volumes
(average daily volumes):
Cushing Terminal 72 69 69 56 43
Ingleside Terminal 11 11 8 3 -
----- ----- ----- ----- -----
Total 83 80 77 59 43
===== ===== ===== ===== =====
Storage leased to third parties
(monthly average volumes):
Cushing Terminal 1,743 890 414 203 208
Ingleside Terminal 232 260 254 211 -
----- ----- ----- ----- -----
Total 1,975 1,150 668 414 208
===== ===== ===== ===== =====
Gathering and Marketing Activities
Our gathering and marketing activities are conducted in 23 states; however,
the vast majority of those activities are in Texas, Louisiana, California,
Illinois and the Gulf of Mexico. 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 proprietary gathering assets or
assets owned and operated by third parties when necessary or cost
effective;
. 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.
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, 1999, we purchased approximately
265,000 barrels per day of crude oil directly at the wellhead from more than
2,200 producers from approximately 10,700 leases. We purchase crude oil from
producers under contracts that range in term from a thirty-day evergreen to
three years.
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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 the unauthorized trading
losses, a significant number of our suppliers and trading partners reduced or
eliminated the amount of open credit previously extended to us. Consequently,
the amount of letters of credit we needed to support the level of crude oil
purchases then in effect increased significantly. In many instances we arranged
for letters of credit to secure our obligations to purchase crude oil from our
customers. In other instances, certain of our purchase contracts were
terminated. As a result of these changes, aggregate volumes purchased are
expected to decrease by 150,000 barrels per day, consisting primarily of lower
unit margin purchases. Approximately 50,000 barrels per day of the decrease is
related to barrels gathered at producer lease locations and 100,000 barrels per
day is attributable to bulk purchases. See "Unauthorized Trading Losses" and
Item 7. - "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources".
The following table shows the average daily volume of our lease gathering and
bulk purchases from 1995 through 1999.
Year Ended December 31,
-----------------------------------------
1999(1) 1998 1997 1996 1995
------- ------ ------ ------- ------
(barrels in thousands)
Lease gathering (1) 265 88 71 59 46
Bulk purchases 138 98 49 32 10
------- ------ ------ ------- ------
Total volumes 403 186 120 91 56
======= ====== ====== ======= ======
---------
(1) Includes volumes from Scurlock Permian since May 1, 1999.
Crude Oil Purchases. 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 utilize our truck fleet and gathering
pipelines and third-party pipelines, trucks and barges to transport the crude
oil to market. We own or lease approximately 280 trucks, 325 tractor-trailers
and 290 injection stations.
We have a Marketing Agreement with Plains Resources Inc., 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 will be adjusted 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.
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 margins associated with our
bulk purchases will fluctuate from period to period. Our bulk purchasing
activities are concentrated in California, Texas, Louisiana and at the Cushing
Interchange.
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 from one month to
three years.
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 with respect to
futures contracts on the NYMEX. Through these transactions, we seek to maintain
a position that is substantially balanced between crude oil purchases and sales
and future delivery obligations. We from time to time enter into fixed price
delivery contracts, floating price collar arrangements, financial swaps and
crude oil futures contracts as hedging devices. Our policy is generally to
purchase only crude oil for which we have a market and to structure our sales
contracts so that crude oil price fluctuations do
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not materially affect the gross margin which we receive. 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. 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. See "Unauthorized Trading Losses".
Risk management strategies, including those involving price hedges using NYMEX
futures contracts, have become increasingly important in creating and
maintaining margins. Such hedging techniques require significant resources
dedicated to managing futures positions. We are able to monitor crude oil
volumes, grades, locations and delivery schedules and to coordinate marketing
and exchange opportunities, as well as NYMEX hedging positions. This
coordination ensures that our NYMEX hedging activities are successfully
implemented. We have recently hired a Risk Manager that has direct
responsibility and authority for our risk policies and our trading controls and
procedures and other aspects of corporate risk management.
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 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 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 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 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 ongoing relationships with
more than 2,200 producers. 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.
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. Due to the
unauthorized trading losses, the amount of letters of credit that we are
required to provide to secure our crude oil purchases has increased. See
"Unauthorized Trading Losses".
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.
Credit review and analysis are also integral to our leasehold purchases.
Payment for all or substantially all of the monthly leasehold production is
sometimes made to the operator of the lease. The operator, in turn, is
responsible for the correct payment and distribution of such production proceeds
to the proper parties. In these situations, we must determine whether the
operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend us in the event any third party should
bring a protest, action or complaint in connection with the ultimate
distribution of production proceeds by the operator.
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OPERATING ACTIVITIES
See Note 17 in the Notes to the Consolidated and Combined Financial Statements
appearing elsewhere in this report for information with respect to our pipeline
activities and terminalling and storage and gathering and marketing activities
and also those of our predecessor.
CUSTOMERS
Sempra Energy Trading Corporation and Koch Oil Company accounted for 22% and
19%, respectively, of our combined 1999 revenues. No other individual customer
accounted for greater than 10% of our revenues in 1999. We believe that the loss
of an individual customer would not have a material adverse effect.
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.
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 regulation. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil 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 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 regulations than are our competitors. Due to the myriad of
complex federal and state statutes and regulations which may affect us, directly
or indirectly, you should not rely on the following discussion of certain
statutes and regulations as an exhaustive review of all regulatory
considerations affecting our operations.
Pipeline Regulation
Our pipelines are subject to regulation by the Department of Transportation
under the Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA")
relating to the design, installation, testing, construction, operation,
replacement and management of pipeline facilities. The HLPSA requires us and
other pipeline operators to comply with regulations issued pursuant to HLPSA, to
permit access to and allow copying of records and to make certain reports and
provide information as required by the Secretary of Transportation.
The Pipeline Safety Act of 1992 amends the HLPSA in several important
respects. It requires the Research and Special Programs Administration of the
Department of Transportation to consider environmental impacts, as well as its
traditional public safety mandate, when developing pipeline safety regulations.
In addition, the Pipeline Safety Act mandates the establishment by the
Department of Transportation of pipeline operator qualification rules requiring
minimum training requirements for operators, and requires that pipeline
operators provide maps and records to the Research and Special Programs
Administration. It also authorizes the Research and Special Programs
Administration to require that pipelines be modified to accommodate internal
inspection devices, to mandate the installation of emergency flow restricting
devices for pipelines in populated or sensitive areas and to order other changes
to the operation and maintenance of petroleum pipelines. We believe that our
pipeline operations are in substantial compliance with applicable HLPSA and
Pipeline Safety Act requirements. Nevertheless, we could incur significant
expenses in the future if additional safety measures are required or if safety
standards are raised and exceed the 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.
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Transportation Regulation
General Interstate Regulation. Our interstate common carrier pipeline
operations are subject to rate regulation by the 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. The
Interstate Commerce Act permits challenges to proposed new or changed rates by
protest, and challenges to rates that are already final and in effect by
complaint. Upon the appropriate showing, a successful complainant may obtain
reparations for overcharges sustained for a period of up to two years prior to
the filing of a complaint.
The FERC is authorized to suspend the effectiveness of a new or changed tariff
rate for a period of up to seven months and to investigate the rate. If upon the
completion of an investigation the FERC finds that the rate is unlawful, it may
require the pipeline operator to refund to shippers, with interest, any
difference between the rates the FERC determines to be lawful and the rates
under investigation. In addition, the FERC will order the pipeline to change its
rates prospectively to the lawful level.
In general, petroleum pipeline rates must be cost-based, although settlement
rates, which are rates that have been agreed to by all shippers, are permitted,
and market-based rates may be permitted in certain circumstances. Under a cost-
of-service basis, rates are permitted to generate operating revenues, on the
basis of projected volumes, not greater than the total of the following:
. operating expenses;
. depreciation and amortization;
. federal and state income taxes; and
. an overall allowed rate of return on the pipeline's "rate base."
Energy Policy Act of 1992 and Subsequent Developments. In October 1992
Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed
petroleum pipeline rates in effect for the 365-day period ending on the date of
enactment of the Energy Policy 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. The Energy Policy Act also provides that complaints
against such rates may only be filed under the following limited circumstances:
. 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;
. the complainant was contractually barred from challenging the rate prior to
enactment; or
. a provision of the tariff is unduly discriminatory or preferential.
The Energy Policy Act further 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. On
October 22, 1993, the FERC responded to the Energy Policy Act directive by
issuing Order No. 561, which adopts a new indexing rate methodology for
petroleum pipelines. Under the new regulations, which were effective January 1,
1995, petroleum pipelines are able to change their rates within prescribed
ceiling levels that are tied to the Producer Price Index for Finished Goods,
minus one percent. Rate increases made pursuant to the index will be 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. The new indexing methodology can be applied to any
existing rate, even if the rate is under investigation. If such rate is
subsequently adjusted, the ceiling level established under the index must be
likewise adjusted.
In Order No. 561, the FERC said that as a general rule pipelines must utilize
the indexing methodology to change their rates. The FERC indicated, however,
that it was retaining cost-of-service ratemaking, market-based rates, and
settlements as alternatives to the indexing approach. A pipeline can follow a
cost-of-service approach when seeking to increase its rates above index levels
for uncontrollable circumstances. A pipeline can seek to charge market- based
rates if it can establish that it lacks market power. In addition, a pipeline
can establish rates pursuant to settlement if agreed upon by all current
shippers. Initial rates for new services can be established through a cost-of-
service proceeding or through an uncontested agreement between the pipeline and
all of its shippers, including at least one shipper not affiliated with the
pipeline.
On May 10, 1996, the Court of Appeals for the District of Columbia Circuit
affirmed Order No. 561. The Court held that by establishing a general indexing
methodology along with limited exceptions to indexed rates, FERC had reasonably
balanced its dual responsibilities of ensuring just and reasonable rates and
streamlining ratemaking through generally
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applicable procedures. The FERC indicated in Order No. 561 that it will assess
in 2000 how the rate-indexing method is operating.
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. This result comports with
the principle that, although a regulated entity is entitled to an allowance to
cover its incurred costs, including income taxes, there should not be an element
included in the cost of service to cover costs not incurred. Opinion No. 397 was
affirmed on rehearing in May 1996. Appeals of the Lakehead opinions were taken,
but the parties to the Lakehead proceeding subsequently settled the case, with
the result that appellate review of the tax and other issues never took place.
A proceeding is also pending on rehearing at the FERC involving another
publicly traded limited partnership engaged in the common carrier transportation
of crude oil (the "Santa Fe Proceeding") in which the FERC could further limit
its current position related to the tax allowance permitted in the rates of
publicly traded partnerships, as well as possibly alter the FERC's current
application of the FERC oil pipeline ratemaking methodology. On January 13,
1999, the FERC issued Opinion No. 435 in the Santa Fe Proceeding, 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. Requests for rehearing of
Opinion No. 435 are pending before the FERC. Petitions for review of Opinion No.
435 are before the D.C. Circuit Court of Appeals, but are being held in abeyance
pending FERC action on the rehearing requests. Once the FERC acts on rehearing,
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, such as those
currently charged by us, which have been mutually agreed to by the pipeline and
the shippers or which are significantly below cost of service rates that might
otherwise be justified by the pipeline under the FERC's cost-based ratemaking
methods. Substantially all of our gross margins on transportation are produced
by rates that are either grandfathered or set by agreement of the parties. These
rates have not been decreased through application of the indexing method. 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 PPFIG-
1 index 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 Santa Fe 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, keeping of 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 OSHA with respect to our trucking operations.
ENVIRONMENTAL REGULATION
General
Various 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
regulation. As with the industry generally, compliance with existing and
anticipated regulations increases our overall cost of business. Areas affected
include capital costs to construct, maintain and upgrade equipment and
facilities. While these regulations affect our capital expenditures and
earnings, we believe that these regulations do not affect our competitive
position in that the operations of our competitors that comply with such
regulations are similarly affected. Environmental regulations have historically
been subject to frequent change by regulatory authorities, and we are unable to
predict the ongoing cost to us of complying with these laws and regulations or
the future impact of such regulations on our operations. Violation of federal or
state environmental laws, regulations and permits can result in the imposition
of significant civil and criminal penalties,
17
<PAGE>
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 applicable regulations and claims by neighboring landowners and other third
parties for personal injury and property damage.
Water
The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of the
Federal Water Pollution Control Act of 1972 ("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 removal
costs 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.
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 are currently being developed under OPA and state laws that
may also impose additional regulatory burdens on our operations.
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 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") 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 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. 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 non-hazardous solid 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. RCRA also governs the
disposal of hazardous 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 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.
Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as "Superfund," imposes 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 and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. 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 of persons the costs they incur. 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.
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<PAGE>
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.
OSHA
We are also subject to the requirements of the Federal Occupational Safety and
Health Act ("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 ("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.
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
limited to an aggregate of $1.0 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. 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. Moreover, 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 or results of operations.
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 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 or
results of operations.
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<PAGE>
From 1994 to 1997, 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. 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 $130,000
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. In
addition, a portion of any such costs may be reimbursed to us from Plains
Resources.
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 may experience damage as a result of an accident or other natural
disaster. These hazards can cause personal injury and loss of life, severe
damage to and destruction of property and equipment, pollution or environmental
damages 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, 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 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 such 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 which
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, such 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 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. Our general partner
believes that it has obtained such 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 which have not
yet been
20
<PAGE>
obtained, our general partner believes that such consents, permits or
authorizations will be obtained within a reasonable period, or that the failure
to obtain such consents, permits or authorizations will have no material adverse
effect on the operation of our business.
Our general partner believes 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, our
general partner believes 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 910 employees at December 31, 1999. None of the employees of our
general partner were represented by labor unions, and our general partner
considers its employee relations to be good.
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, et al. The suit alleged
that Plains All American Pipeline, L.P. and certain of our 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 name our general
partner and Plains Resources as additional defendants. Plaintiffs allege that
the defendants are 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.
The court has consolidated all subsequently filed cases under the first filed
action described above. Two unopposed motions are currently pending to appoint
lead plaintiffs. These motions ask the court to appoint two distinct lead
plaintiffs to represent two different plaintiff classes: (1) purchasers of
Plains Resources common stock and options and (2) purchasers of our common
units. Once lead plaintiffs have been appointed, the plaintiffs will file their
consolidated amended complaints. No answer or responsive pleading is due until
thirty days after a consolidated amended complaint is filed.
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 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 derivative complaints
allege, among other things, that Plains All American Pipeline has been harmed
due to the negligence or breach of loyalty of the officers and directors that
are named in the lawsuits. These cases are currently in the process of being
consolidated. No answer or responsive pleading is due until these cases have
been consolidated and a consolidated complaint has been filed.
We intend to vigorously defend the claims made in the Texas securities
litigation and the Delaware derivative litigation. However, there can be no
assurance that we will be successful in our defense or that these lawsuits will
not have a material adverse effect on our financial position or results of
operation.
We, in the ordinary course of business, are a claimant and/or a defendant in
various other legal proceedings. Management does 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 or results of operation.
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.
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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 22, 2000, the
market price for the common units was $16 3/8 per unit and there were
approximately 11,700 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
---------- --------------- -------------
1999:
1st Quarter $ 19 $ 15 7/8 $ 0.450
2nd Quarter 19 15/16 16 5/16 0.463
3rd Quarter 20 17 3/8 0.481
4th Quarter 20 1/4 9 5/8 0.450 (1)
1998:
4th Quarter $ 20 3/16 $ 16 1/4 $ 0.193 (2)
------------
(1) A distribution was not made on the subordinated units for the fourth
quarter of 1999.
(2) Represents a partial quarterly distribution for the period from November
23, 1998, the date of our initial public offering, to December 31, 1998.
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.
We have also issued subordinated units, all of which are held by an affiliate
of our general partner, for which there is no established public trading market.
Subject to the consent of our lenders, we will distribute to our partners
(including holders of subordinated units), on a quarterly basis, all of our
available cash in the manner described herein. 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
(prorated for the initial partial fiscal quarter commencing November 23, 1998,
the closing date of our initial public offering through year-end 1998).
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
expiration of the subordination period will generally not occur prior to
December 31, 2003.
Under the terms of our amended bank credit agreement and letter of credit and
borrowing facility, we are required to have lender approval to declare or pay
distributions to unitholders and 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 of
Financial Condition and Results of Operations - Liquidity and Capital
Resources".
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ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
(in thousands, except unit 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 historical financial information below for Plains All American Pipeline was
derived from our audited consolidated financial statements as of December 31,
1999 and 1998, and for the year ended December 31, 1999 and for the period from
November 23, 1998 through December 31, 1998. The pro forma financial information
for the year ended December 31, 1998 was derived from our audited consolidated
financial statements for the period from November 23, 1998 through December 31,
1998 and from the audited combined financial statements of our predecessor for
the period from January 1, 1998 through November 22, 1998. The financial
information below for our predecessor was derived from the audited combined
financial statements of our predecessor, as of December 31, 1997, 1996, and 1995
and for the period from January 1, 1998 through November 22, 1998 and for the
years ended December 31, 1997, 1996, and 1995, including the notes thereto. The
operating data for all periods is derived from our records as well as those of
our predecessor. 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 and combined 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".
<TABLE>
<CAPTION>
Predecessor
---------------------------------------------------
November 23, January 1,
Year Ended December 31, 1998 To 1998 To Year Ended December 31,
---------------------------- December 31, November 22, -------------------------------------
1999 1998 (1)(2) 1998 (1) 1998 (1) 1997 1996 1995
----------- ----------- --------- --------- --------- --------- ----------
(restated) (restated) (restated)
(proforma)
(unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues (restated)(1) $ 4,739,892 $ 1,631,489 $ 180,591 $1,011,734 $ 835,757 $ 613,881 $ 396,018
Cost of sales and
operations (restated)(1) 4,629,578 1,557,368 173,092 980,753 823,277 604,350 389,652
Unauthorized trading losses
and related expenses (1) 166,440 7,100 2,400 4,700 - - -
----------- ----------- --------- --------- --------- --------- ----------
Gross margin (56,126) 67,021 5,099 26,281 12,480 9,531 6,366
----------- ----------- --------- --------- --------- --------- ----------
General and administrative
expenses 23,211 6,501 771 4,526 3,529 2,974 2,415
Depreciation and amortization 17,344 11,303 1,192 4,179 1,165 1,140 944
Restructuring expense 1,410 - - - - - -
----------- ----------- --------- --------- --------- --------- ----------
Total expenses 41,965 17,804 1,963 8,705 4,694 4,114 3,359
----------- ----------- --------- --------- --------- --------- ----------
Operating income (loss) (97,078) 49,217 3,136 17,576 7,786 5,417 3,007
Interest expense (21,139) (12,991) (1,371) (11,260) (4,516) (3,559) (3,460)
Gain on sale of linefill 16,457 - - - - - -
Interest and other income 958 584 12 572 138 90 115
----------- ----------- --------- --------- --------- --------- ----------
Net income (loss)
before provision (benefit)
in lieu of income taxes
and extraordinary item (101,815) 36,810 1,777 6,888 3,408 1,948 (338)
Provision (benefit) in
lieu of income taxes - - - 2,631 1,268 726 (93)
----------- ----------- --------- --------- --------- --------- ----------
Net income (loss) before
extraordinary item $ (101,815) $ 36,810 $ 1,777 $ 4,257 $ 2,140 $ 1,222 $ (245)
=========== =========== ========= ========= ========= ========= ==========
Basic and diluted
net income (loss) per
limited partner unit before
extraordinary item (3) $ (3.16) $ 1.20 $ 0.06 $ 0.25 $ 0.12 $ 0.07 $ (0.01)
=========== =========== ========= ========= ========= ========= ==========
Weighted average
number of limited partner
units outstanding 31,633 30,089 30,089 17,004 17,004 17,004 17,004
=========== =========== ========= ========= ========= ========= ==========
Table and footnotes continued on next page
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
Predecessor
---------------------------------------------------
November 23, January 1,
Year Ended December 31, 1998 To 1998 To Year Ended December 31,
---------------------------- December 31, November 22, -------------------------------------
1999 1998 (1) 1998 (1) 1998 (1) 1997 1996 1995
----------- ----------- --------- --------- --------- --------- ----------
(restated) (restated) (restated)
(proforma)
(unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
(AT END OF PERIOD):
Working capital (4) $ 101,539 N/A $ 2,231 N/A $ 2,017 $ 2,586 $ 3,055
Total assets 1,223,037 N/A 607,186 N/A 149,619 122,557 82,076
Related party debt
Long-term 114,000 N/A - N/A 28,531 31,811 32,095
Total debt (5) 368,819 N/A 184,750 N/A 18,000 - -
Partners' capital 192,973 N/A 270,543 N/A - - -
Combined equity - N/A - N/A 5,975 3,835 2,613
OTHER DATA:
EBITDA (6) $ 89,074 $ 68,204 $ 6,740 $ 27,027 $ 9,089 $ 6,647 $ 4,066
Maintenance capital
expenditures (7) 1,741 2,091 200 1,508 678 1,063 571
OPERATING DATA:
Volumes (barrels per day):
All American
Tariff (8) 100,600 124,500 110,200 113,700 - - -
Margin (9) 56,200 49,200 50,900 49,100 - - -
Other 61,400 - - - - - -
----------- ----------- --------- --------- --------- --------- ----------
Total pipeline 218,200 173,700 161,100 162,800 - - -
=========== =========== ========= ========= ========= ========= ==========
Lease gathering (10) 264,700 108,500 126,200 87,100 71,400 58,500 45,900
Bulk purchases (11) 138,200 97,900 133,600 94,700 48,500 31,700 10,200
----------- ----------- --------- --------- --------- --------- ----------
Total 402,900 206,400 259,800 181,800 119,900 90,200 56,100
=========== =========== ========= ========= ========= ========= ==========
Terminal throughput (12) 83,300 79,800 61,900 81,400 76,700 59,800 42,500
=========== =========== ========= ========= ========= ========= ==========
</TABLE>
---------
(1) 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). Approximately $7.1 million of the unauthorized trading losses
was recognized in 1998 and as a result, we have restated our 1998 financial
information. See Item 1. - "Business - Unauthorized Trading Losses". We
have restated Revenues and Costs of Sales and Operations to appropriately
reflect certain transactions with Plains Resources.
(2) The unaudited selected pro forma financial and operating data for the year
ended December 31, 1998, is based on our historical financial statements
and those of our predecessor and Wingfoot Ventures Seven, Inc., a wholly-
owned subsidiary of Goodyear. The historical financial statements of
Wingfoot reflect the historical operating results of the All American
Pipeline and the SJV Gathering System through July 30, 1998. Effective July
30 1998, our predecessor acquired the All American Pipeline and SJV
Gathering system from Goodyear for approximately $400.0 million. The pro
forma selected financial data reflects certain pro forma adjustments to the
historical results of operations as if we had been formed and the
acquisition had taken place on January 1, 1998.
(3) 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 general partner in exchange for the assets contributed to the
partnership.
(4) 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 Item 1. -
"Acquisitions and Dispositions - All American Pipeline Linefill and Asset
Disposition".
(5) Excludes related party debt.
(6) EBITDA means earnings before interest expense, income taxes, depreciation
and amortization. Adjusted EBITDA also excludes unauthorized trading
losses, noncash compensation, restructuring expense, linefill gain 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.
(7) 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.
(8) Represents crude oil deliveries on the All American Pipeline for the
account of third parties.
(9) Represents crude oil deliveries on the All American Pipeline and the SJV
Gathering System for the account of affiliated entities. These volumes were
transported on the segment of the line that was sold. See "All American
Pipeline Linefill Sale and Asset Disposition."
(10) Represents barrels of crude oil purchased at the wellhead, including
volumes which would have been purchased under the Marketing Agreement.
(11) Represents barrels of crude oil purchased at collection points, terminals
and pipelines.
(12) Represents total crude oil barrels delivered from the Cushing Terminal and
the Ingleside Terminal.
24
<PAGE>
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 and those of the midstream subsidiaries of Plains Resources (our
"predecessor") should be read in conjunction with our historical consolidated
and combined financial statements and accompanying notes and those of our
predecessor included elsewhere in this report. For more detailed information
regarding the basis of presentation for the following financial information, see
the notes to the historical consolidated and combined 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. Our operations are conducted through Plains Marketing, L.P., All
American Pipeline, L.P. and Plains Scurlock Permian, L.P. Plains All American
Inc., a wholly-owned subsidiary of Plains Resources, is our general partner. We
are engaged in interstate and intrastate marketing, transportation and
terminalling of crude oil. 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."
Pipeline Operations. Our activities from pipeline operations generally consist
of transporting third-party volumes of crude oil for a tariff and merchant
activities designed to capture price differentials between the cost to purchase
and transport crude oil to a sales point and the price received for such crude
oil at the sales point. Tariffs on our pipeline systems vary by receipt point
and delivery point. The gross margin generated by our tariff activities depends
on the volumes transported on the pipeline and the level of the tariff charged,
as well as the fixed and variable costs of operating the pipeline. Our ability
to generate a profit on margin activities is not tied to the absolute level of
crude oil prices but is generated by the difference between an index related
price paid and other costs incurred in the purchase of crude oil and an index
related price at which we sell crude oil. We are well positioned to take
advantage of these price differentials due to our ability to move purchased
volumes on our pipeline systems. We combine reporting of gross margin for tariff
activities and margin activities due to the sharing of fixed costs between the
two activities.
Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage activities is dependent on the
throughput volume of crude oil stored and the level of fees generated at our
terminalling and storage facilities. 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 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 (as was the case in late
1997, 1998 and the first quarter of 1999), the market for crude oil is often in
contango, meaning that the price of crude oil in a given month is less than the
price of crude oil in a subsequent month. 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 low 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 in a given month exceeds the price of crude
oil in a subsequent month. A backward market has a positive impact on marketing
margins because crude oil gatherers can capture a premium for prompt deliveries.
We believe that the combination of our terminalling and storage activities and
gathering and marketing activities provides a counter-cyclical balance which has
a stabilizing effect on our operations and cash flow.
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 with respect to
futures contracts on the NYMEX. Through these transactions, we seek to maintain
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 which will
expose us to basis risk. Basis risk occurs when crude oil is purchased based on
a crude oil specification and location which is different from the
countervailing sales arrangement. Our policy is only to purchase 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 which we receive.
In November 1999, we discovered
25
<PAGE>
that this policy was violated, and we incurred $174.0 million in unauthorized
trading losses, including associated costs and legal expenses. 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. See Item 1. "Business -Unauthorized Trading Losses".
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). Approximately $7.1 million of the unauthorized trading losses was
recognized in 1998 and the remainder in 1999. As a result, we have restated our
1998 financial information. See Item 1. "Business - 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.
Results of Operations
Historical Analysis of Three Years Ended December 31, 1999.
The historical 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. The combined
historical results of operations for the year ended December 31, 1998 are
derived from our historical financial statements for the period from November
23, 1998 through December 31, 1998, and the combined financial statements of our
predecessor for the period from January 1, 1998 through November 22, 1998, which
in the following discussion are combined and referred to as the year ended
December 31, 1998. Commencing July 30, 1998 (the date of acquisition of the All
American Pipeline and the SJV Gathering System from Goodyear), the results of
operations of the All American Pipeline and the SJV Gathering System are
included in the results of operations of the predecessor.
For 1999, we reported a net loss of $103.4 million on total revenue of $4.7
billion compared to net income for 1998 of $6.0 million on total revenue of $1.2
billion and net income for 1997 of $2.1 million on total revenue of $835.8
million. The results for the years ended December 31, 1999 and 1998 include the
following unusual or nonrecurring items:
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; and
. an extraordinary loss of $1.5 million related to the early extinguishment
of debt.
1998
. $7.1 million of unauthorized trading losses.
Excluding these nonrecurring items, we would have reported net income of $49.6
million and $11.2 million for the years ended December 31, 1999 and 1998,
respectively. Excluding the unauthorized trading losses, we reported gross
margin (revenues less direct expenses of purchases, transportation, terminalling
and storage and other operating and maintenance expenses) of $110.3 million for
the year ended December 31, 1999 compared to $38.5 million reported for 1998.
Gross profit (gross margin less general and administrative expense), also
excluding the unauthorized trading losses, was $88.1 million for the year ended
December 31, 1999 as compared to $33.2 million for 1998.
26
<PAGE>
The following table sets forth historical and combined historical financial
and operating information of Plains All American Pipeline for the periods
presented and includes the impact of the nonrecurring items discussed above (in
thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1999 1998 1997
---------- ---------- -------------
(restated) (predecessor)
<S> <C> <C> <C>
Operating Results:
Revenues (restated) $4,739,892 $1,192,325 $ 835,757
========== ========== =============
Gross margin
Pipeline $ 58,001 $ 16,768 $ -
Terminalling and storage
and gathering and marketing 52,313 21,712 12,480
Unauthorized trading losses (166,440) (7,100) -
---------- ---------- -------------
Total (56,126) 31,380 12,480
General and administrative expense (23,211) (5,297) (3,529)
---------- ---------- -------------
Gross profit $ (79,337) $ 26,083 $ 8,951
========== ========== =============
Net income (loss) $ (103,360) $ 5,979 $ 2,140
========== ========== =============
Average Daily Volumes (barrels):
Pipeline Activities:
All American
Tariff activities 101 113 -
Margin activities 56 50 -
Other 61 - -
---------- ---------- -------------
Total 218 163 -
========== ========== =============
Lease gathering 265 88 71
Bulk purchases 138 98 49
---------- ---------- -------------
Total 403 186 120
========== ========== =============
Terminal throughput 83 80 77
========== ========== =============
Storage leased to third parties,
monthly average volumes 1,975 1,150 668
========== ========== =============
</TABLE>
Revenues. Revenues increased to $4.7 billion from $1.1 billion and $0.8
billion in 1998 and 1997, respectively. The increase in 1999 as compared to 1998
was primarily due to an increase in lease gathering and bulk purchase volumes,
resulting from the Scurlock acquisition in May 1999, and higher crude oil
prices. The increase in 1998 from 1997 reflects the acquisition of the All
American Pipeline in July 1998 as well as increased lease gathering and bulk
purchase volumes. These increases in 1998 were partially offset by lower crude
oil prices. The NYMEX benchmark WTI crude oil price averaged $19.25 per barrel
in 1999, $14.43 per barrel in 1998, and $20.63 per barrel in 1997.
Cost of Sales and Operations. Cost of sales and operations increased to $4.6
billion from $1.2 billion and $0.8 billion in 1998 and 1997, respectively,
primarily due to the reasons discussed above for revenues.
General and Administrative. General and administrative expenses were $23.2
million for the year ended December 31, 1999, compared to $5.3 million and $3.5
million for 1998 and 1997, respectively. These increases were primarily
attributable to the Scurlock and West Texas Gathering System acquisitions in
1999 ($13.1 million), the All American Pipeline acquisition in 1998 ($0.7
million), expenses related our operations as a public entity ($0.7 million) and
continued expansion of our business activities. The increase in 1998 compared to
1997 is primarily due to the July 1998 All American Pipeline acquisition and
expansion of our business activities. As a result of the unauthorized trading
losses, we will incur increased expenses in 2000, primarily accounting and
consulting related.
Noncash compensation expense. During 1999, we incurred a charge of $1.0
million related to noncash incentive compensation paid to certain officers and
key employees of Plains All American Inc., our general partner. In 1998, Plains
All American Inc. granted its employees the right to earn ownership in our
common units owned by Plains All American Inc. The units vest over a three-year
period subject to paying distributions on the common and subordinated
units. This amount is included in general and administrative expense on the
Consolidated Statements of Operations.
27
<PAGE>
Depreciation and Amortization. Depreciation and amortization expense was $17.3
million in 1999, $5.4 million in 1998 and $1.2 million in 1997. The increase in
1999 is due primarily to the Scurlock and West Texas Gathering System
acquisitions in 1999 and the All American Pipeline acquisition in July 1998. The
increase in 1998 is due to the All American Pipeline acquisition.
Interest expense. Interest expense was $21.1 million in 1999, $12.6 million in
1998 and $4.5 million in 1997. The increase in 1999 is due to (1) interest
associated with the debt incurred for the Scurlock and West Texas Gathering
System acquisitions, (2) a full year of interest for the All American Pipeline
acquisition, (3) an increase in interest related to hedged inventory
transactions and (4) an increase in interest rates as a result of the
unauthorized trading losses. The increase in interest expense in 1998 is
associated with the debt incurred for the acquisition of the All American
Pipeline and the SJV Gathering System. Interest expense in 1997 is comprised
principally of interest charged to our predecessor by Plains Resources for
amounts borrowed to construct the Cushing Terminal and subsequent capital
additions, including the Ingleside Terminal.
Nonrecurring Items
Gain on sale of linefill. We initiated the sale of 5.2 million barrels of
crude oil linefill from the All American Pipeline in November 1999. The sale was
substantially completed in February 2000. The linefill was located in the
segment of the All American Pipeline that extends from Emidio, California, to
McCamey, Texas. Proceeds from the sale of the linefill were approximately $100.0
million, net of associated costs, and were used for working capital purposes. We
estimate that we will recognize a total gain of approximately $44.6 million in
connection with the sale of the linefill. As of December 31, 1999, we had
delivered approximately 1.8 million barrels of linefill and recognized a gain of
$16.5 million.
Unauthorized trading losses. As previously discussed, we recognized losses of
approximately $166.4 million and $7.1 million in 1999 and 1998, respectively, as
a result of unauthorized trading by a former employee.
Restructuring charge. 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. As a result of the restructuring,
we expect to reduce cash compensation costs by approximately $1.3 million per
year.
Extraordinary item. 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 $58.0 million
for the year ended December 31, 1999, compared to $16.8 million for 1998. The
increase resulted from twelve months of results from the All American Pipeline
in 1999 versus five months in 1998, increased margins from our pipeline merchant
activities, and to the two 1999 acquisitions which contributed approximately
$4.8 million of pipeline gross margin. The increase was partially offset by
lower tariff transport volumes, due to lower production from Exxon's Santa Ynez
Field and the Point Arguello Field, both offshore California. Volumes from these
fields have steadily declined from 1995 through 1999. 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 $2.6 million.
The margin between revenue and direct cost of crude purchased was $33.5
million for the year ended December 31, 1999, compared to $3.9 million for 1998.
Pipeline tariff revenues were approximately $46.4 million for the year ended
December 31, 1999, compared to approximately $19.0 million for 1998. Pipeline
operations and maintenance expenses were approximately $24.0 million for the
year ended December 31, 1999, as compared to $6.1 million for 1998.
Tariff transport volumes on the All American Pipeline decreased from an
average of 113,000 barrels per day for the year ended December 31, 1998, to
101,000 barrels per day in 1999 due primarily to a decrease in shipments of
offshore California production, which decreased from 90,000 barrels per day in
1998 to 79,000 barrels per day in 1999. Barrels associated with our merchant
activities on the All American Pipeline increased from 50,000 barrels per day in
1998 to 56,000 barrels per day for the year ended December 31, 1999. Tariff
volumes shipped on the Scurlock and West Texas Gathering systems averaged 61,000
barrels per day during 1999.
In March 2000, we sold the segment of the All American Pipeline that extends
from Emidio, California to McCamey, Texas. We initiated the sale of
approximately 5.2 million barrels of crude oil linefill from the All American
Pipeline in November 1999. The sale of the linefill was substantially complete
in February 2000. We estimate that we will recognize a
28
<PAGE>
total gain of approximately $44.6 million in connection with the sale of the
linefill. As of December 31, 1999, we had delivered approximately 1.8 million
barrels of linefill and recognized a gain of $16.5 million. During 1999, we
reported gross margin of approximately $5.0 million associated with operating
the segment of the All American Pipeline that was sold. See Item 1. -
"Business -Acquisitions and Dispositions".
The following table sets forth the All American Pipeline average deliveries
per day within and outside California (in thousands):
Year Ended December 31,
-----------------------
1999 1998
-------- ---------
Deliveries:
Average daily volumes (barrels):
Within California 101 111
Outside California 56 52
-------- ---------
Total 157 163
======== =========
Gathering and Marketing Activities and Terminalling and Storage Activities.
Excluding the unauthorized trading losses, gross margin from terminalling and
storage and gathering and marketing activities was approximately $52.3 million
for the year ended December 31, 1999, reflecting a 141% increase over the $21.7
million reported for 1998 and a 319% increase over the $12.5 million reported
for 1997. The increase in gross margin is due to an increase in lease gathering
and bulk purchase volumes, primarily as a result of the Scurlock acquisition,
which contributed approximately $26.3 million of 1999 gross margin, and an
increase in storage capacity leased at our Cushing Terminal. Lease gathering
volumes increased from an average of 88,000 and 71,000 barrels per day in 1998
and 1997, respectively, to approximately 265,000 barrels per day in 1999. Bulk
purchase volumes increased from approximately 98,000 and 49,000 barrels per day
for 1998 and 1997, respectively, to approximately 138,000 barrels per day this
year. Leased terminal capacity increased significantly from approximately 1.1
and 0.7 million barrels per month in 1998 and 1997, respectively, to 2.0 million
barrels per month during 1999. The 1.1 million barrel expansion of our Cushing
Terminal was placed in service in the second quarter of 1999. Throughput volumes
at our terminals increased approximately 3,000 and 6,000 barrels per day in the
current year period from 1998 and 1997, respectively.
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 the amended 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. As a result of these
changes, aggregate volumes purchased are expected to decrease by 150,000 barrels
per day, consisting primarily of lower unit margin purchases. Approximately
50,000 barrels per day of the decrease is related to barrels gathered at
producer lease locations and 100,000 barrels per day is attributable to bulk
purchases. As a result of the increase in letter of credit costs and reduced
volumes, annual Adjusted EBITDA is expected to be adversely affected by
approximately $5.0 million, excluding the positive impact of current favorable
market conditions.
Pro Forma Comparison of the Years Ended December 31, 1999 and 1998
The following discussion presents a comparison of our historical results for
1999 and pro forma results for 1998. The pro forma adjustments to the historical
results of operations for 1998 assume that we had been formed and that we had
acquired the All American Pipeline and the SJV Gathering System on January 1,
1998.
For the year ended December 31, 1999, we reported a net loss of $103.4 million
on total revenue of $4.7 billion compared to net income for the year ended
December 31, 1998 of $36.8 million on total revenue of $1.6 billion. The results
for the years ended December 31, 1999 and 1998 include the following unusual or
nonrecurring items:
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; and
. an extraordinary loss of $1.5 million related to the early extinguishment
of debt.
29
<PAGE>
1998
. $7.1 million of unauthorized trading losses.
Excluding these nonrecurring items further discussed in the preceding
historical results, we would have reported net income of $49.6 million and $43.9
million for the years ended December 31, 1999 and 1998, respectively. Excluding
the unauthorized trading losses, we reported gross margin (revenues less direct
expenses of purchases, transportation, terminalling and storage and other
operating and maintenance expenses) of $110.3 million for the year ended
December 31, 1999 compared to $74.1 million reported for 1998. Gross profit
(gross margin less general and administrative expense), also excluding the
unauthorized trading losses, was $88.1 million for the year ended December 31,
1999 as compared to $67.6 million for 1998.
The following table sets forth certain historical and pro forma financial and
operating information of Plains All American Pipeline for the periods presented.
The following pro forma financial and operating information does not include pro
forma adjustments related to the Scurlock and West Texas Gathering System
acquisitions which were effective May 1, 1999 and July 1, 1999, respectively (in
thousands).
Year Ended December 31,
------------------------
1999 1998
---------- ----------
(historical) (pro forma)
(restated)
Operating Results:
Revenues (restated) $4,739,892 $1,631,489
========== ==========
Gross margin
Pipeline $ 58,001 $ 50,893
Terminalling and storage
and gathering and marketing 52,313 23,228
Unauthorized trading losses (166,440) (7,100)
---------- ----------
Total (56,126) 67,021
General and administrative expense (23,211) (6,501)
---------- ----------
Gross profit $ (79,337) $ 60,520
========== ==========
Net income (loss) $ (103,360) $ 36,810
========== ==========
Average Daily Volumes (barrels):
Pipeline Activities:
All American
Tariff activities 101 125
Margin activities 56 49
Other 61 -
---------- ----------
Total 218 174
========== ==========
Lease gathering 265 108
Bulk purchases 138 98
---------- ----------
Total 403 206
========== ==========
Terminal throughput 83 80
========== ==========
Storage leased to third parties,
monthly average volumes 1,975 1,150
========== ==========
Revenues. Revenues were $4.7 billion for the year ended December 31, 1999,
compared to $1.6 billion for 1998 on a pro forma basis. The increase in 1999 as
compared to 1998 was primarily due to an increase in lease gathering and bulk
purchase volumes, resulting from the Scurlock acquisition in May 1999, and
higher crude oil prices. The NYMEX benchmark WTI crude oil price averaged $19.25
per barrel in 1999 compared to $14.43 per barrel in 1998.
Cost of Sales and Operations. Cost of sales and operations were $4.6 billion
for the year ended December 31, 1999 compared to $1.6 billion for 1998 on a pro
forma basis. The increase in 1999 as compared to 1998 was primarily due to the
reasons discussed above for revenues.
General and Administrative. General and administrative expenses were $23.2
million for the year ended December 31, 1999, compared to $6.5 million for 1998
on a pro forma basis. The increase in 1999 as compared to the 1998 pro forma
amount is due to the Scurlock and West Texas Gathering System acquisitions in
1999 ($13.1 million), expenses related to the
30
<PAGE>
operation of Plains All American Pipeline as a public entity ($0.9 million) and
continued expansion of our business activities. As a result of the unauthorized
trading losses, we will incur additional expenses in 2000, primarily accounting
and consulting related.
Noncash compensation expense. During 1999, we incurred a charge of $1.0
million related to noncash incentive compensation paid to certain officers and
key employees of Plains All American Inc., our general partner. In 1998, Plains
All American Inc. granted the employees the right to earn ownership in our
common units owned by Plains All American Inc. The units vest over a three-year
period subject to paying distributions on the common and subordinated units.
This amount is included in general and administrative expense on the
Consolidated Statements of Operations.
Depreciation and Amortization. Depreciation and amortization expense was
$17.3 million for the year ended December 31, 1999, compared to $11.3 million on
a pro forma basis for 1998. The increase is primarily due to the Scurlock
acquisition and the West Texas Gathering System acquisition.
Interest expense. Interest expense was $21.1 million for the year ended
December 31, 1999, compared to $13.0 million on a pro forma basis for 1998. The
increase is due to (1) interest associated with the debt incurred for the
Scurlock acquisition, (2) the West Texas Gathering System acquisition, (3) an
increase in interest related to hedged inventory transactions and (4) an
increase in interest rates as a result of the unauthorized trading losses.
Pipeline Operations. Gross margin from pipeline operations was $58.0
million for the year ended December 31, 1999 compared to $50.9 million for the
prior year on a pro forma basis. The increase resulted from increased margins
from our pipeline merchant activities, a reduction in operating costs
attributable to the All American Pipeline and to the two 1999 acquisitions which
contributed approximately $4.8 million of pipeline gross margin. The increase
was partially offset by lower tariff transport volumes, due to lower production
from Exxon's Santa Ynez Field and the Point Arguello Field, both offshore
California. Volumes from these fields have steadily declined from 1995 through
1999. 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 $2.6
million.
The margin between revenue and direct cost of crude oil purchased was $33.5
million for the year ended December 31, 1999 compared to $14.5 million on a pro
forma basis for 1998. Pipeline tariff revenues were approximately $46.4 million
for the year ended December 31, 1999 compared to approximately $57.5 million on
a pro forma basis in 1998. Pipeline operations and maintenance expenses were
approximately $24.0 million for the year ended December 31, 1999 as compared to
$26.1 million on a pro forma basis for 1998.
Tariff transport volumes on the All American Pipeline decreased from an
average of 125,000 barrels per day for the year ended December 31, 1998 on a pro
forma basis to 101,000 barrels per day in 1999 due primarily to a decrease in
shipments of offshore California production, which decreased from 94,000 barrels
per day on a pro forma basis in 1998 to 79,000 barrels per day in 1999. Barrels
associated with our merchant activities on the All American Pipeline increased
from 49,000 barrels per day on a pro forma basis to 56,000 barrels per day for
the year ended December 31, 1999. Tariff volumes shipped on the Scurlock and
West Texas Systems averaged 61,000 barrels per day during 1999.
In March 2000, we sold the segment of the All American Pipeline that
extends from Emidio, California to McCamey, Texas. We initiated the sale of
approximately 5.2 million barrels of crude oil linefill from the All American
Pipeline in November 1999. The sale of the linefill was substantially complete
in February 2000. We estimate that we will recognize a total gain of
approximately $44.6 million in connection with the sale of the linefill. As of
December 31, 1999, we have delivered approximately 1.8 million barrels of
linefill and recognized a gain of $16.5 million. During 1999, we reported gross
margin of approximately $5.0 million associated with operating the segment of
the All American Pipeline that was sold. See Item 1. - "Business - Acquisitions
and Dispositions".
The following table sets forth All American Pipeline average deliveries per
day within and outside California for the periods presented (in thousands).
<TABLE>
<CAPTION>
Year Ended
December 31,
---------------------------
1999 1998
------------ -----------
(historical) (pro forma)
<S> <C> <C>
Deliveries:
Average daily volumes (barrels):
Within California 101 115
Outside California 56 59
----- -----
Total 157 174
===== =====
</TABLE>
31
<PAGE>
Gathering and Marketing Activities and Terminalling and Storage Activities.
Excluding the unauthorized trading losses, gross margin from gathering,
marketing, terminalling and storage activities was approximately $52.3 million
for the year ended December 31, 1999 compared to $23.2 million in the prior year
on a pro forma basis. The increase in gross margin is due to an increase in
lease gathering and bulk purchase volumes, primarily as a result of the Scurlock
acquisition which contributed approximately $26.3 million of 1999 gross margin,
and an increase in storage capacity leased at our Cushing Terminal. Lease
gathering volumes increased from an average of 108,000 barrels per day on a pro
forma basis for the year ended December 31, 1998 to approximately 265,000
barrels per day in 1999. Bulk purchase volumes increased from approximately
98,000 barrels per day for 1998 to approximately 138,000 barrels per day this
year. Leased terminal capacity increased significantly from approximately 1.1
million barrels per month in 1998 to 2.0 million barrels per month during 1999.
The 1.1 million barrel expansion of our Cushing Terminal was placed in service
in the second quarter of 1999. Throughput volumes at our terminals increased
approximately 3,000 barrels per day in the current year period.
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 the amended 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. As a result of these changes, aggregate volumes purchased are
expected to decrease by 150,000 barrels per day, consisting primarily of lower
unit margin purchases. Approximately 50,000 barrels per day of the decrease is
related to barrels gathered at producer lease locations and 100,000 barrels per
day is attributable to bulk purchases. As a result of the increase in letter of
credit costs and reduced volumes, annual Adjusted EBITDA is expected to be
adversely affected by approximately $5.0 million, excluding the positive impact
of current favorable market conditions.
Liquidity and Capital Resources
General
The financial loss resulting from the unauthorized trading activity placed
us in default under certain of the covenants of our credit facilities and also
created significant liquidity issues. In December 1999, we executed amended
credit facilities and obtained default waivers from all of our lenders. In
connection with the amendments, our general partner loaned us approximately
$114.0 million. By May 2000 our liquidity was significantly improved through the
sales of the segment of the All American Pipeline and the related crude oil
linefill for total proceeds of $224.0 million and the refinancing of our credit
facilities. Consolidated debt subsequent to the May 2000 refinancing was
approximately $256.0 million, as compared to $369.0 million at December 31,
1999.
In May 2000, we entered into two new credit facilities totaling $700.0
million. See "Credit Facilities." The new facilities provide us with significant
working capital availability, as well as flexibility for both internal and
external growth opportunities. Giving effect to the repayment of existing debt
and closing costs, we had approximately $256.0 million outstanding on our
revolving credit facility as of May 8, 2000. Accordingly, we have approximately
$144.0 million of additional borrowing capacity for acquisitions, capital
expansion projects and general working capital purposes. In addition, the
capacity available under the letter of credit facility should enable us to
absorb additional acquisitions of other midstream assets and entities.
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.
Cash Flows
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
(in millions) 1999 1998 1997
-----------------------------------------------------------------------------
(restated) (predecessor)
(combined)
(unaudited)
<S> <C> <C> <C>
Cash provided by (used in):
Operating activities $(106.2) $ 29.8 $(12.9)
Investing activities (186.1) (402.7) (1.9)
Financing activities 340.5 386.4 14.3
-----------------------------------------------------------------------------
</TABLE>
32
<PAGE>
Operating Activities. Net cash used in operating activities in 1999
resulted 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 for 1999
included approximately $176.9 million for acquisitions, primarily for the
Scurlock and West Texas gathering system, $11.1 million for expansion capital
and $1.7 million for maintenance capital. Approximately $5.0 million and $4.2
million, respectively, related to the Cushing terminal expansion is included in
expansion capital expenditures for 1999 and 1998, respectively. Net cash used in
investing activities for 1998 consisted primarily of approximately $394.0
million for the purchase of the All American Pipeline and SJV Gathering System.
Financing activities. 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
two subordinated notes to our general partner. Cash inflows from financing
activities during 1998 included (1) $283.8 million from the net issuance of
short-term and long-term debt and (2) a capital contribution of approximately
$113.7 million from our general partner primarily in connection with the
acquisition of the All American Pipeline and SJV Gathering System.
Cash distributions paid to unitholders on our outstanding common units,
Class B units and subordinated units in 1999 were $51.7 million. Included in
this amount is $5.9 million representing distributions for the period from our
inception, November 23, 1998 through December 31, 1998. On February 14, 2000, we
paid a cash distribution of $0.45 per unit on our outstanding common units and
Class B units. The distribution was paid to unitholders of record on February 7,
2000 for the period covering October 1, 1999 through December 31, 1999. The
total distribution paid was approximately $11.2 million, with approximately $7.2
million paid to our public unitholders and the remainder paid to our general
partner for its limited and general partner interests. We received the requisite
consent from our lenders to pay the fourth quarter distribution. No distribution
was declared on the subordinated units owned by our general partner.
In October 1999, we completed a public offering of an additional 2,990,000
common units, representing limited partner interests, at $18.00 per unit. Net
proceeds, including our general partners' contribution, were approximately $51.3
million after deducting underwriters' discounts and commissions and offering
expenses of approximately $3.1 million. The proceeds, together with our general
partner's capital contribution of approximately $0.5 million to maintain its 2%
general partner interest, were used to reduce outstanding debt. Approximately
$44.0 million was used to reduce the term loan portion of the Plains Scurlock
bank credit agreement and the remainder was used to reduce the balance
outstanding on our other revolving credit facility.
Working Capital
At December 31, 1999, we had working capital of approximately $101.5
million. Working capital at December 31, 1999 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 Item 1. "Business -
Acquisitions and Dispositions - All American Pipeline Linefill Sale and Asset
Disposition." Proceeds from the linefill sale of approximately $100.0 million
were used to repay short term working capital loans incurred in December 1999
and January 2000 and to fund the portion of the unauthorized trading losses that
were settled in cash during the first quarter of 2000. Proceeds from the sale of
the pipeline of approximately $129.0 million were used to reduce our outstanding
debt under our bank credit agreement. We had working capital of approximately
$2.2 million at December 31, 1998.
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 intend to make aggregate
capital expenditures of approximately $9.0 million in 2000 and believe that we
will have sufficient cash from working capital, cash flow and draws under our
revolving credit facility under our bank credit agreement. We estimate that
capital expenditures necessary to maintain our existing asset base at current
operating levels will be approximately $4.0 million to $5.0 million each year.
Commitments
The aggregate amounts of maturities of all long-term indebtedness for the
next five years based on balances outstanding subsequent to the May 2000
refinancing are: 2001 - $1.7 million, 2002 - $6.9 million, 2003 - $27.2 million,
and 2004 - $262.9 million. These amounts consist principally of amounts due
under our revolving credit facilities.
33
<PAGE>
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. The expiration of the subordination
period will generally not occur prior to December 31, 2003. There were no
arrearages on common units at December 31, 1999.
In connection with our crude oil marketing, we provide certain purchasers
and transporters with irrevocable standby letters of credit to secure their
obligation for the purchase of crude oil. Generally, these letters of credit are
issued for up to seventy day periods and are terminated upon completion of each
transaction. At December 31, 1999, we had outstanding letters of credit of
approximately $321.5 million. Such letters of credit are secured by our crude
oil inventory and accounts receivable.
As is common within the industry, we have entered into various commitments
and agreements related 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.
Credit Agreements
Amounts borrowed under our credit agreements before and after refinancing
were as follows (in thousands):
<TABLE>
<CAPTION>
December 31, May 8,
1999 2000
------------ ----------
<S> <C> <C>
New Plains Marketing, L.P. revolving credit facility $ - $256,000
New Plains Marketing, L.P. letter of credit and hedged inventory facility - 20,250
All American Pipeline, L.P. bank credit agreement 225,000 -
Plains Scurlock bank credit agreement 85,100 -
Plains Marketing, L.P. letter of credit and borrowing facility 13,719 -
Secured term credit facility 45,000 -
Subordinated note payable - general partner 114,000 -
--------- --------
$ 482,819 $276,250
========= ========
</TABLE>
The unauthorized trading losses discovered in November 1999 resulted in a
default of the covenants under our credit facilities and significant short-term
cash and letter of credit requirements. In December 1999, we executed amended
credit facilities and obtained default waivers from all our lenders. We paid
approximately $13.7 million in connection with the amended credit facilities.
On May 8, 2000, we entered into new bank credit agreements. The borrower
under the new facilities is Plains Marketing, L.P., one of our subsidiaries. We
are a guarantor of the obligations under the credit facilities. The obligations
are also guaranteed by the subsidiaries of Plains Marketing, L.P. We entered
into the credit agreements in order to:
. refinance the existing bank debt of Plains Marketing, L.P. and Plains
Scurlock Permian, L.P. in conjunction with the merger of these
subsidiaries;
. refinance existing bank debt of All American Pipeline, L.P.;
. repay to our general partner $114.0 million plus accrued interest of
subordinated debt; and
. provide additional flexibility for working capital, capital
expenditures, and for other general corporate purposes.
Our new bank credit agreements consist of:
. a $400.0 million senior secured revolving credit facility. At closing,
we had $256.0 million outstanding under the revolving credit facility.
The revolving credit facility is secured by substantially all of our
assets and matures in April 2004. No principal is scheduled for
payment prior to maturity. The revolving credit facility bears
interest at our option at either the base rate, as defined, plus an
applicable margin, or LIBOR plus an applicable margin. We incur a
commitment fee on the unused portion of the revolving credit facility.
34
<PAGE>
. A $300.0 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 for resale and
borrowings to finance crude oil inventory which has 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 which has been hedged against
future price risk. The letter of credit facility expires in April
2003. Aggregate availability under the letter of credit facility for
direct borrowings and letters of credit is limited to a borrowing base
which is determined monthly based on certain of our current assets and
current liabilities, primarily accounts receivable and accounts
payable related to the purchase and sale of crude oil. At closing,
there were letters of credit of approximately $173.8 million and
borrowings of approximately $20.3 million outstanding under this
facility.
Our bank credit agreements 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 prohibited contracts; and
. enter into a merger or consolidation.
Our bank credit agreements 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 that 4.0 to 1.0 for the
period from March 31, 2000, to March 31, 2002, and subsequently 3.75
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 0.65 to 1.0.
A default under our bank credit agreements 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 bank
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. Under the most
restrictive of these covenants, at May 8, 2000, we could have borrowed the full
$400.0 million available under our secured revolving credit facility.
Contingencies
Since our announcement in November 1999 of our losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits have
been filed against us, certain of our general partner's officers and directors
and in some of these cases, our 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 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. 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. 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.
35
<PAGE>
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 and the price at which we sell crude oil.
The gross margin generated by tariff activities depends on the volumes
transported on the pipeline and the level of the tariff 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.
A significant portion of our gross margin is derived from the Santa Ynez
and Point Arguello fields located offshore California. 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 59,000 and 20,000 average daily
barrels, respectively, for the year ended December 31, 1999. We expect that
there will continue to be natural production declines from each of these fields
as the underlying reservoirs are depleted. As operator of Point Arguello, Plains
Resources is conducting additional drilling and other activities on this field,
but we cannot assure you that these activities will affect the production
decline. 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
$2.6 million.
As previously discussed, our future results will also be affected by (1)
decreased gross margin due to the sale of the segment of the All American
Pipeline, (2) declines in offshore California production transported on the All
American Pipeline and (3) reduced lease gathering and bulk purchase volumes and
increased expenses resulting from the unauthorized trading losses.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS 133"). SFAS 133 requires that all
derivative instruments be recorded on the balance sheet 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 an asset's, liability's, or firm commitment's fair value, changes in the fair
value of the derivative instrument will generally be offset in the income
statement by changes in the hedged item's fair value. 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. 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. This statement was amended by Statement of Financial Accounting Standards
No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral
of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June
1999. SFAS 137 defers the effective date of SFAS 133 to fiscal years beginning
after June 15, 2000. We are required to adopt this statement beginning in 2001.
We have not yet determined the effect that the adoption of SFAS 133 will have on
our financial position or results of operations.
Year 2000
Year 2000 Project. In order to address the Year 2000 issue, we initiated a
Year 2000 project. We incurred approximately $0.8 million through December 31,
1999, in connection with our Year 2000 project, approximately $0.4 million of
which were costs paid to third parties. We did not encounter any critical system
application, hardware or equipment failures during the date roll over to the
Year 2000, and have not experienced any disruptions of business activities as a
result of Year 2000 failures by our customers, suppliers, service providers or
business partners.
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. We do not enter into derivative transactions for speculative trading
purposes. Substantially all of our derivative contracts are exchanged or traded
with major financial institutions and the risk of credit loss is considered
remote.
36
<PAGE>
Commodity Price Risk. The fair value of outstanding derivative instruments
and the change in fair value that would be expected from a 10 percent adverse
price change are shown in the table below (in millions):
<TABLE>
<CAPTION>
December 31,
----------------------------------------------
1999 1998
--------------------- ---------------------
10% 10%
Adverse Adverse
Fair Price Fair Price
Value Change Value Change
--------- --------- --------- ----------
<S> <C> <C> <C> <C>
Crude oil :
Futures contracts $ - $(2.8) $ 1.8 $(0.3)
Swaps and options contracts (0.6) (0.1) - -
</TABLE>
The fair values of the futures contracts are based on quoted market prices
obtained from the NYMEX. The fair value of the swaps are estimated based on
quoted prices from independent reporting services compared to the contract price
of the swap which approximate 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 adverse change in prices
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.
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, 1999. Our variable rate debt bears interest at LIBOR
plus the applicable margin. The average interest rates presented below are based
upon rates in effect at December 31, 1999. The carrying value of variable rate
bank debt approximates fair value as interest rates are variable, based on
prevailing market rates (dollars in millions).
<TABLE>
<CAPTION>
Expected Year of Maturity Fair
---------------------------------------------------------------------
2000 2001 2002 2003 2004 Thereafter Total Value
-------- -------- -------- -------- -------- ---------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Liabilities:
Short-term debt - variable rate $ 58.7 $ - $ - $ - $ - $ - $ 58.7 $ 58.7
Average interest rate 8.74% 8.74%
Long-term debt - variable rate 50.6 0.6 3.2 0.7 80.0 289.0 424.1 424.1
Average interest rate 8.45% 9.06% 9.40% 9.06% 9.06% 8.44% 8.57%
</TABLE>
At December 31, 1998, the carrying value of short-term and long-term debt
of $9.7 million and $175.0 million, respectively, approximated fair value.
Interest rate swaps and collars are used to hedge underlying debt
obligations. These instruments hedge 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, 1999, we
had interest rate swap and collar arrangements for an aggregate notional
principal amount of $215.0 million, which positions had an aggregate value of
approximately $0.4 million as of such date. These instruments are based on LIBOR
margins and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0
million of debt and a floor of 6% and a ceiling of 8% for $125.0 million of
debt. In August 1999, we terminated our swap arrangements on an aggregate
notional principal amount of $175.0 million and we received consideration in the
amount of approximately $10.8 million.
At December 31, 1998, we had an interest rate swap arrangement for an
aggregate notional principal amount of $175.0 million and would have been
required to pay approximately $2.2 million to terminate the instrument at that
date.
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.
37
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
PARTNERSHIP MANAGEMENT
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 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 that 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 may not be 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. In addition, the members of the conflicts committee also serve on an
audit committee which reviews our external financial reporting, recommends
engagement of our independent auditors and reviews procedures for internal
auditing and the adequacy of our internal accounting controls.
As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by the officers and are subject to the oversight of the
directors of our general partner. Most of our operational personnel are
employees of our general partner.
Some officers of our general partner may spend a substantial amount of time
managing the business and affairs of Plains Resources and its affiliates. These
officers may face a conflict regarding the allocation of their time between our
business and the other business interests of Plains Resources. Our general
partner intends to cause its officers to devote as much time to the management
of our business and affairs as is necessary for the proper conduct of our
business and affairs.
DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
The following table sets forth certain information with respect to the
executive officers and members of the Board of Directors of our general partner.
Executive officers and directors are elected for one year terms.
<TABLE>
<CAPTION>
NAME AGE POSITION WITH OUR GENERAL PARTNER
--------------------------------- --- -----------------------------------------------------------------
<S> <C> <C>
Greg L. Armstrong 41 Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis 42 President, Chief Operating Officer and Director
Phillip D. Kramer 44 Executive Vice President and Chief Financial Officer
George R. Coiner 48 Senior Vice President
Michael R. Patterson 52 Senior Vice President, General Counsel and Secretary
Michael J. Latiolais 45 Vice President - Administration
Mark F. Shires 42 Vice President - Operations
Cynthia A. Feeback 42 Treasurer
Everardo Goyanes 55 Director and Member of Audit and Conflicts Committees
Robert V. Sinnott 50 Director and Member of Audit and Compensation
Committees
Arthur L. Smith 47 Director and Member of Audit, Conflicts and Compensation
Committees
</TABLE>
Greg L. Armstrong has served as Chairman of the Board, Chief Executive Officer
and Director of our general partner since its formation. In addition, he has
been President, Chief Executive Officer and Director of Plains Resources since
1992. 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.
38
<PAGE>
Harry N. Pefanis has served as President, Chief Operating Officer and Director
of our general partner since its formation. In addition, he has been Executive
Vice President - Midstream of Plains Resources since May 1998. 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 the Plains
Midstream Subsidiaries until the formation of Plains All American Pipeline.
Phillip D. Kramer has served as Executive Vice President and Chief Financial
Officer of our general partner since its formation. In addition, he has been
Executive Vice President, Chief Financial Officer and Treasurer of Plains
Resources since May 1998. He previously served Plains Resources as: Senior Vice
President, Chief Financial Officer and Treasurer from May 1997 until May 1998;
Vice President, Chief Financial Officer and Treasurer from 1992 to 1997; Vice
President and Treasurer from 1988 to 1992; Treasurer from 1987 to 1988; and
Controller from 1983 to 1987.
George R. Coiner has served as Senior Vice President of our general partner
since its formation. In addition, he was Vice President of Plains Marketing &
Transportation Inc., a Plains Midstream Subsidiary, since November 1995. Prior
to joining Plains Marketing & Transportation Inc., he was Senior Vice President,
Marketing with Scurlock Permian Corp.
Michael R. Patterson has served as Senior Vice President, General Counsel and
Secretary of our general partner since its formation. In addition, he has been
Vice President, General Counsel and Secretary of Plains Resources since 1988. He
previously served Plains Resources as Vice President and General Counsel from
1985 to 1988.
Michael J. Latiolais has served as Vice President - Administration of our
general partner since August 1999 and as Controller of our general partner from
July 1998 through August 1999. In addition, he was Vice President and Controller
for All American Pipeline Company, Celeron Gathering Corporation and Celeron
Trading & Transportation Company from 1994 until such companies were merged into
the operating partnerships of Plains All American Pipeline. He served as
Controller of such companies from 1985 to 1994.
Mark F. Shires has served as Vice President - Operations of our general
partner since August 1999. He served as Manager of Operations for our general
partner from April 1999 until August 1999 when 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 Plains Midstream
Subsidiary, from 1993 to 1996.
Cynthia A. Feeback has served as Treasurer of our general partner since its
formation. In addition, she has been Vice President - Accounting and Assistant
Treasurer of Plains Resources since May 1999. She previously served Plains
Resources as Assistant Treasurer, Controller and Principal Accounting Officer
from May 1998 to May 1999; Controller and Principal Accounting Officer from 1993
to 1998; Controller from 1990 to 1993; and Accounting Manager from 1988 to 1990.
Everardo Goyanes has served as a Director and a member of Audit and Conflicts
Committees since May 1999. Mr. Goyanes is a financial consultant specializing in
natural resources. From 1989 to 1998, he was Managing Director of the Natural
Resources Group of ING Baring Furman Selz (a commercial banking firm). He was a
financial consultant from 1987 to 1989 and was Vice President - Finance of
Forest Oil Corporation from 1983 to 1987.
Robert V. Sinnott has served as a Director and a member of Audit and
Compensation Committees since September 1998. Mr. Sinnott has been Vice
President of Kayne Anderson Investment Management, Inc. (an investment
management firm) since 1992. 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 and a member of Audit, Conflicts and
Compensation Committees 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. Mr. Smith served as a director of
Pioneer Natural Resources Company from 1997 to 1998 and of Parker & Parsley
Petroleum Company from 1991 to 1997.
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
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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 1999 our officers and directors complied with all filing
requirements with respect to our equity securities.
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 and its affiliates, including Plains Resources, perform services
for us and are reimbursed by us for all expenses incurred on our behalf,
including the costs of employee, officer and director compensation and benefits
properly allocable to us, as well as all other expenses necessary or appropriate
to the conduct of our business and properly allocable to us. 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.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
We were formed in September 1998 but conducted no business until late November
1998. Accordingly, prior to 1999, no officer of our general partner received
salary and bonus compensation for services to the partnership in excess of
$100,000. Messrs. Armstrong, Pefanis, Kramer and Patterson and Ms. Feeback are
compensated by Plains Resources and do not receive compensation from our general
partner with the exceptions of awards to Messrs. Armstrong and Pefanis under the
Long-Term Incentive Plan and the Transaction Grant Agreements described below.
However, we reimburse our general partner and its affiliates, including Plains
Resources for expenses incurred on our behalf, including the costs of officer
compensation properly allocable to us. See Item 13. - "Certain Relationships
and Related Transactions - Relationship with Plains Resources". The following
table sets forth certain compensation information for all executive officers of
our general partner who received salary and bonus compensation from our general
partner in excess of $100,000 in 1999 (the "Named Executive Officers").
<TABLE>
<CAPTION>
Annual Compensation Long-Term
-------------------------- Compensation Other
Name and Principal Position Year Salary Bonus LTIP Payouts Compensation
--------------------------- ---- --------- ---------- ------------- -------------
<S> <C> <C> <C> <C> <C>
George Coiner 1999 $ 180,956 $ 295,000 (1) $ 167,073 (2) $ 10,000 (3)
Senior Vice President
Michael J. Latiolais 1999 152,267 76,133 - 10,000 (3)
Vice President - Administration 71,110 (4)
Mark F. Shires 1999 160,792 (5) 77,500 - -
Vice President - Operations
</TABLE>
----------
(1) Paid under Management Incentive Plan. See " - Management Incentive Plan"
below.
(2) Represents the value of 11,111 common units as of December 31, 1999 plus
distribution equivalent rights with respect to such units, which vested
under the Transaction Grant Agreement. See - "Transaction Grant
Agreements" below.
(3) Plains Resources matches 100% of an employee's 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 are granted).
(4) Represents reimbursement of moving and relocation expenses.
(5) Includes $51,000 for consulting fees we paid to Mr. Shires prior to his
becoming an employee of our general partner in April 1999.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS
Plains Resources has an employment agreement with Mr. Armstrong which expires
on March 1, 2002 (unless extended pursuant to the terms thereof) and 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 two times his annual base salary. If his employment
is terminated as a result of a change in control of Plains Resources, he will be
entitled to receive an amount equal to three times the aggregate of his annual
base salary and bonus. In either event, Mr. Armstrong will be entitled to
receive medical benefits for two years following the date of his termination.
Under Mr. Armstrong's agreement, a change in control of Plains Resources is
defined as the directors in office on the date of the agreement ceasing to
constitute a majority of the Board of Directors of Plains Resources.
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Plains Resources also has an employment agreement with Mr. Pefanis, under
which Mr. Pefanis serves as Executive Vice President of Plains Resources as well
as President and Chief Operating Officer of our general partner and is
responsible for our overall operations. The employment agreement provides that
Plains Resources will not require Mr. Pefanis to engage in activities that
materially detract from his duties and responsibilities as an officer of our
general partner. The initial term of the employment agreement runs through
November 23, 2001, subject to annual extensions and includes confidentiality,
nonsolicitation and noncompete provisions, which, in general, will continue for
two years following termination of Mr. Pefanis' employment. The employment
agreement provides for an annual base salary of $235,000, subject to annual
review. If Mr. Pefanis' employment is terminated without cause, he will be
entitled to receive an amount equal to two times his base salary. Upon a Change
in Control of Plains Resources or a Marketing Operations Disposition (as such
terms are defined in the employment agreement), the term of the employment
agreement will be automatically extended for three years, and if Mr. Pefanis'
employment is terminated during the one-year period following either event by
him for a Good Reason or by Plains Resources other than for death, disability or
Cause (as such terms are defined in the employment agreement), he will be
entitled to a lump sum severance amount equal to three times the sum of (1) his
highest rate of annual base salary and (2) the largest annual bonus paid during
the three preceding years.
Long-Term Incentive Plan
Our general partner has adopted the Plains All American Inc. 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 975,000 common units. The plan is administered by the
Compensation Committee of our general partner's board of directors.
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, 2000, an aggregate of approximately 500,000 restricted units have been
authorized for grants to employees of our general partner, 170,000 of which have
been granted with the remaining 330,000 to be granted in the near future. Grants
made include 60,000, 30,000 and 12,500 units to Messrs. Pefanis, Coiner and
Latiolais, respectively. 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. In general, restricted
units granted to employees during the subordination period will vest only upon,
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 will
be eligible to vest prior to termination of the subordination period.
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, common units already owned by our general partner,
common units acquired by our general partner directly from us or any other
person, or any combination of the foregoing. Our general partner will be
entitled to reimbursement by us for the cost incurred in acquiring common units.
If we issue new common units upon vesting of the restricted units, the total
number of common units outstanding will increase. Following the subordination
period, the Compensation Committee, in its discretion, may grant tandem
distribution equivalent rights with respect to restricted units.
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, purchased directly from us or any other
person, or use 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 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
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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.
The unit option plan has been designed to furnish additional compensation to
employees and directors and to align their economic interests with those of the
common unitholders. 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.
TRANSACTION GRANT AGREEMENTS
In addition to the grants made under the Restricted Unit Plan described above,
our general partner, at no cost to us, agreed to transfer approximately 400,000
of its affiliates' common units (including distribution equivalent rights
attributable to such units) to certain key employees of our general partner. A
grant covering 50,000 of such common units was terminated in 1999. Generally,
approximately 69,444 of the remaining common units vest in each of the years
ending December 31, 1999, 2000 and 2001 if the operating surplus generated in
such year equals or exceeds the amount necessary to pay the minimum quarterly
distribution on all outstanding common units and the related distribution on the
general partner interest. If a tranche of common units does not vest in a
particular year due to a common unit arrearage, such common units will vest at
the time the common unit arrearages for such year have been paid. In addition,
approximately 47,224 of the remaining common units vest in each of the years
ending December 31, 1999, 2000 and 2001 if the operating surplus generated in
such year exceeds the amount necessary to pay the minimum quarterly distribution
on all outstanding common units and subordinated units and the related
distribution on the general partner interest. In 1999, approximately 69,444 of
such common units vested and 47,224 of such common units remain unvested as no
distribution on the subordinated units was made for the fourth quarter of 1999.
Any common units remaining unvested shall vest upon, and in the same proportion
as, the conversion of subordinated units to common units. Distribution
equivalent rights are paid in cash at the time of the vesting of the associated
common units. Notwithstanding the foregoing, all common units become vested if
Plains All American Inc. is removed as our general partner prior to January 1,
2002.
The compensation expense incurred in connection with these grants will be
funded by our general partner, without reimbursement by us. Under these grants,
75,000 common units were allocated to each of Messrs. Armstrong and Pefanis and
50,000 common units were allocated to Mr. Coiner.
MANAGEMENT INCENTIVE PLAN
Our general partner has adopted the Plains All American Inc. Management
Incentive Plan. The Management Incentive Plan is designed to enhance the
performance of our general partner's key employees by rewarding them with cash
awards for achieving quarterly and/or annual financial performance objectives.
The Management Incentive Plan is administered by the Compensation Committee.
Individual participants and payments, if any, for each fiscal quarter and year
are determined by and in the discretion of the Compensation Committee. Any
incentive payments are at the discretion of the Compensation Committee, and our
general partner may amend or change the Management Incentive Plan at any time.
Our general partner is entitled to reimbursement by us for payments and costs
incurred under the plan.
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. Messrs. Armstrong and
Pefanis, as officers of our general partner, are otherwise compensated for their
services to our general partner and therefore receive no separate compensation
for their services as directors of our general partner.
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<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units held by
beneficial owners of 5% or more of the units, by directors and officers of our
general partner and by all directors and executive officers of our general
partner as a group as of March 15, 2000.
<TABLE>
<CAPTION>
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
----------------------------- ----------- ---------- ------------ ------------ ------------- ------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Plains Resources Inc. (1) 6,904,795 (3) 30.0% 1,307,190 100.0% 10,029,619 100% 53.1%
Plains All American Inc. (2) 6,904,795 (3) 30.0% 1,307,190 100.0% 10,029,619 100% 53.1%
Goldman, Sachs & Co. 1,278,325 (4) 5.6% - - - - 3.7%
Greg L .Armstrong 95,000 (3) (6) - - - - (6)
Harry N. Pefanis 147,000 (3)(5) (6) - - - - (6)
Phillip D. Kramer 6,000 (6) - - - - (6)
George R. Coiner 85,000 (3)(5) (6) - - - - (6)
Michael R. Patterson 7,000 (6) - - - - (6)
Michael J. Latiolais 12,500 (5) (6) - - - - (6)
Mark F. Shires - (6) - - - - (6)
Cynthia A. Feeback 500 (6) - - - - (6)
Everado Goyanes - (6) - - - - (6)
Robert V. Sinnot 5,000 (6) - - - - (6)
Arthur L. Smith 7,500 (6) - - - - (6)
All directors and executive
officers as a group
(11 persons) 365,500 1.6% (7) - - - - 1.1% (7)
---------------
</TABLE>
(1) Plains Resources Inc. is the sole stockholder of Plains All American Inc.,
our general partner. The address of Plains Resources Inc. is 500 Dallas,
Suite 700, Houston, Texas 77002.
(2) The address of Plains All American Inc. is 500 Dallas, Suite 700, Houston,
Texas 77002. The record holder of such common units and subordinated units
is PAAI LLC, a wholly-owned subsidiary of Plains All American Inc., whose
address is 500 Dallas, Suite 700, Houston, Texas 77002.
(3) Includes 280,556 common units owned by affiliates of our general partner to
be transferred to employees pursuant to transaction grant agreements,
subject to certain vesting conditions. The recipients and their initial
grants included: Mr. Armstrong - 75,000 (8,333 units currently vested); Mr.
Pefanis - 75,000 (16,667 units currently vested); and Mr. Coiner - 50,000
(11,111 units currently vested). See Item 11. - "Executive Compensation -
Transaction Grant Agreements".
(4) 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
1,278,325 common units owned by their customers.
(5) Includes the following unvested common units issuable under the Long-Term
Incentive Plan to: Mr. Pefanis - 60,000; Mr. Coiner - 30,000; and Mr.
Latiolais - 12,500. See Item 11. - "Executive Compensation - Long-Term
Incentive Plan."
(6) Less than one percent.
(7) Assumes the vesting of the units granted pursuant to the transaction grant
agreements and under the long-term incentive plan as described in footnotes
(3) and (5) above to the named officers and directors. See Item 11. -
"Executive Compensation - Long-Term Incentive Plan" for vesting conditions
of these grants.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
RIGHTS OF OUR GENERAL PARTNER
Our general partner and its affiliates own 8,211,985 common units, including
1,307,190 Class B common units, and 10,029,619 subordinated units, representing
an aggregate 52.5% limited partner interest in the Plains All American Pipeline.
In addition, our general partner owns an aggregate 2% general partner interest
in Plains All American Pipeline and the operating partnerships on a combined
basis. Through our general partner's ability, as general partner, to manage and
operate Plains All American Pipeline and the ownership of 8,211,985 common
units, including 1,307,190 Class B common units, and all of the outstanding
subordinated units by our general partner and its affiliates (effectively giving
our general partner the ability to veto certain actions of Plains All American
Pipeline), our general partner has the ability to control the management of
Plains All American Pipeline.
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RELATIONSHIP WITH PLAINS RESOURCES
General
Plains Resources controls our general partner, which is its wholly-owned
subsidiary. We have extensive ongoing relationships with Plains Resources. These
relationships include but are not limited to:
. an Omnibus Agreement that provides for (1) the resolution of certain
conflicts arising from the fact that we and Plains Resources conduct
related businesses and (2) our general partner's indemnification of us for
certain matters; and
. a Marketing Agreement with Plains Resources that provides for the marketing
of Plains Resources' equity crude oil production.
Transactions with Affiliates
On May 12, 1999, Plains Scurlock Permian, L.P., a limited partnership of which
Plains All American Inc. is our general partner and Plains Marketing, L.P. is
the limited partner, completed the acquisition of Scurlock Permian LLC from
Marathon Ashland Petroleum LLC. See Item 7. - "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources". To finance a portion of the purchase price, we sold 1.3
million Class B common units to our general partner at $19.125 per unit, the
market value of our common units on May 12, 1999.
The Class B 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
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 units have the same voting rights as the common units.
For the year ended December 31, 1999, Plains Resources produced approximately
20,400 barrels per day which were subject to the Marketing Agreement. We paid
approximately $131.5 million for such production and recognized profits of
approximately $1.5 million under the terms of that agreement.
Our general partner has sole responsibility for conducting our business and
managing our operations and owns all of the incentive distribution rights. Some
of the senior executives who currently manage our business also manage and
operate the business of Plains Resources. 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. For the year ended December 31, 1999, our general partner and its
affiliates incurred $44.7 million of direct and indirect expenses on our behalf.
Of this amount, $142,000 and $212,000 represented reimbursement for the services
of Messrs. Armstrong and Pefanis, respectively, as officers of our general
partner.
In December 1999, following the losses we incurred as a result of the
unauthorized trading activity by a former employee, our general partner loaned
us approximately $114.0 million. This subordinated debt is due not later than
November 30, 2005. Funding to our general partner for these loans was provided
by Plains Resources. See Item 7. - "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources".
Indemnity from Our General Partner
In connection with the acquisition of the All American Pipeline and the SJV
Gathering System in July 1998, Wingfoot agreed to indemnify our general partner
for certain environmental and other liabilities. The indemnity is subject to
limits of:
. $10.0 million with respect to matters of corporate authorization and title
to shares;
. $21.5 million with respect to condition of rights-of-way, lease rights and
undisclosed liabilities and litigation; and
. $30.0 million with respect to environmental liabilities resulting from
certain undisclosed and pre-existing conditions.
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Wingfoot has no liability, however, until the aggregate amount of losses, with
respect to each such category exceeds $1.0 million. These indemnities will
remain in effect until July 2000, with the exception of the environmental
indemnity, which will remain in effect until July 2001. However, upon the
transfer to an unaffiliated third party of a major portion of the assets
acquired from Wingfoot, the indemnities automatically terminate. The
environmental indemnity is also subject to certain sharing ratios which change
based on whether the claim is made in the first, second or third year of the
indemnity as well as the amount of such claim. We have also agreed to be solely
responsible for the cumulative aggregate amount of losses resulting from the oil
leak from the All American Pipeline to the extent such losses do not exceed
$350,000. Any costs in excess of $350,000 will be applied to the $1.0 million
deductible for the Wingfoot environmental indemnity. Our general partner has
agreed to indemnify us for environmental and other liabilities to the extent it
is indemnified by Wingfoot. However, if the sale of the linefill from the All
American Pipeline and the subsequent sale of such pipeline to EPNG Pipeline
Company are construed to constitute a sale of a major portion of the assets
acquired from Wingfoot, the indemnities by Wingfoot will terminate. See Items 1.
and 2. - "Business and Properties - Acquisitions and Dispositions - All American
Pipeline Linefill Sale and Asset Disposition".
Plains Resources has agreed to indemnify us for environmental liabilities
related to the assets of the our predecessor transferred to us that arose prior
to closing and are discovered within three years after closing (excluding
liabilities resulting from a change in law after closing). Plains Resources'
indemnification obligation is capped at $3.0 million.
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<PAGE>
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 -- Second Amended and Restated Agreement of Limited Partnership of
Plains All American Pipeline, L.P. dated as of November 23, 1998
(incorporated by reference to Exhibit 3.1 to Annual Report on Form
10-K for the Year Ended December 31, 1998).
3.2 -- Amended and Restated Agreement of Limited Partnership of Plains
Marketing, L.P. dated as of November 23, 1998 (incorporated by
reference to Exhibit 3.2 to Annual Report on Form 10-K for the Year
Ended December 31, 1998).
3.3 -- Amended and Restated Agreement of Limited Partnership of All
American Pipeline, L.P. dated as of November 23, 1998 (incorporated
by reference to Exhibit 3.3 to Annual Report on Form 10-K for the
Year Ended December 31, 1998).
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 -- Agreement of Limited Partnership of Plains Scurlock Permian, L.P.
dated as of April 29, 1999 (incorporated by reference to Exhibit 3.7
to Quarterly Report on Form 10-Q for the Quarter Ended March 31,
1999).
3.8 -- Amendment No. 1 to the Second Amended and Restated Agreement of
Limited Partnership of Plains All American Pipeline L.P. dated as of
May 12, 1999 (incorporated by reference to Exhibit 3.8 to Quarterly
Report on Form 10-Q for the Quarter Ended June 30, 1999).
10.01 -- Contribution, Conveyance and Assumption Agreement among Plains All
American Pipeline, L.P. and certain other parties dated as of
November 23, 1998 (incorporated by reference to Exhibit 10.03 to
Annual Report on Form 10-K for the Year Ended December 31, 1998).
**10.02 -- Plains All American Inc., 1998 Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.04 to Annual Report on
Form 10-K for the Year Ended December 31, 1998).
**10.03 -- Plains All American Inc., 1998 Management Incentive Plan Plains All
American Inc., 1998 Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.05 to Annual Report on Form 10-K for the
Year Ended December 31, 1998).
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<PAGE>
**10.04 -- Employment Agreement between Plains Resources Inc. and Harry N.
Pefanis dated as of November 23, 1998 (incorporated by reference to
Exhibit 10.06 to Annual Report on Form 10-K for the Year Ended
December 31, 1998).
10.05 -- 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).
10.06 -- 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).
10.07 -- 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).
10.08 -- 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).
**10.09 -- Form of Transaction Grant Agreement (Payment on Vesting)
(incorporated by reference to Exhibit 10.12 to Registration
Statement, file No. 333-64107).
10.10 -- 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).
10.11 -- 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).
10.12 -- 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).
**10.13 -- 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)
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10.14 -- 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.
10.15 -- Credit Agreement [Letter of Credit and Hedged Inventory Facility]
dated May 8, 2000, 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 10.01 to the Quarterly Report on Form 10-Q for the Quarter
Ended March 31, 2000).
10.16 -- Credit Agreement [Revolving Credit Facility] dated May 8, 2000, 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 10.02 to the Quarterly
Report on Form 10-Q for the Quarter Ended March 31, 2000.
21.1 -- Subsidiaries of the Registrant (incorporated by reference to
Exhibit 21.1 to Registration Statement on Form S-1, file no. 333-
86907).
*23.1 -- Consent of PricewaterhouseCooper, LLP.
*27.1 -- Financial Data Schedule
---------
* Filed herewith
** Management contract or compensatory plan or arrangement
(B) REPORTS ON FORM 8-K
A Current Report on Form 8-K was filed on November 29, 1999, regarding the
discovery of unauthorized trading activity by a former employee which was
expected to result in losses to us of approximately $160.0 million.
A Current Report on Form 8-K was filed on December 1, 1999, regarding the
execution of agreements with our lenders to provide for a $300.0 million
credit facility and the waiver of defaults under certain covenants in our
credit facilities which resulted from our unauthorized trading losses, as
well as the execution by Plains Resources of commitment letters for the sale
of up to $50.0 million of a new series of preferred stock, the proceeds of
which would constitute a portion of the $114.0 million in debt financing
which Plains Resources agreed to provide to us.
48
<PAGE>
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 ALL AMERICAN INC.,
Our General Partner
Date: January 18, 2001 By: /s/ Phillip D. Kramer
------------------------------------
Phillip D. Kramer, Executive Vice
President and
Chief Financial Officer
49
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P.
INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Financial Statements
Report of Independent Accountants..................................................................... F-2
Report of Independent Accountants..................................................................... F-3
Consolidated Balance Sheets as of December 31, 1999 and 1998.......................................... F-4
Consolidated and Combined Statements of Operations:
For the year ended December 31, 1999
For the period from inception (November 23,1998) to December 31, 1998
For the period from January 1, 1998 to November 22, 1998 and
the year ended December 31, 1997 (Predecessor)..................................................... F-5
Consolidated and Combined Statements of Cash Flows:
For the year ended December 31, 1999
For the period from inception (November 23,1998) to December 31, 1998
For the period from January 1, 1998 to November 22, 1998 and
the year ended December 31, 1997 (Predecessor)..................................................... F-6
Consolidated Statements of Changes in Partners' Capital for the period from inception (November 23,
1998) to December 31, 1998 and for the year ended December 31, 1999................................. F-7
Notes to Consolidated and Combined Financial Statements............................................... F-8
</TABLE>
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
F-1
<PAGE>
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, after the restatement described in Note 3, present fairly, in all
material respects, the financial position of Plains All American Pipeline, L.P.
and subsidiaries (the "Partnership") at December 31, 1999 and 1998, and the
results of their operations and their cash flows for the year ended December 31,
1999 and the period from inception (November 23, 1998) to December 31, 1998 in
conformity with accounting principles generally accepted in the United States.
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,
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 the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 29, 2000
F-2
<PAGE>
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 combined statements of operations and of cash
flows of the Plains Midstream Subsidiaries, the predecessor entity of the
Partnership, after the restatement described in Note 3, present fairly, in all
material respects, the combined results of their operations and their cash flows
for the period from January 1, 1998 to November 22, 1998 and the year ended
December 31, 1997 in conformity with accounting principles generally accepted in
the United States. These financial statements are the responsibility of the
Plains Midstream Subsidiaries' 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, 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 the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 29, 2000
F-3
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
<TABLE>
<CAPTION>
December 31,
--------------------------
1999 1998
----------- ---------
(restated)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 53,768 $ 5,503
Accounts receivable and other 508,920 120,615
Inventory 34,826 37,711
Assets held for sale (Note 5) 141,486 -
----------- ---------
Total current assets 739,000 163,829
----------- ---------
PROPERTY AND EQUIPMENT 454,878 378,835
Less allowance for depreciation and amortization (11,581) (799)
----------- ---------
443,297 378,036
----------- ---------
OTHER ASSETS
Pipeline linefill 17,633 54,511
Other 23,107 10,810
----------- ---------
$ 1,223,037 $ 607,186
=========== =========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 485,400 $ 144,080
Due to affiliates 42,692 7,768
Short-term debt and current portion of long-term debt 109,369 9,750
----------- ---------
Total current liabilities 637,461 161,598
LONG-TERM LIABILITIES
Bank debt 259,450 175,000
Subordinated note payable - general partner 114,000 -
Other long-term liabilities and deferred credits 19,153 45
----------- ---------
Total liabilities 1,030,064 336,643
----------- ---------
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS' CAPITAL
Common unitholders (23,049,239 and 20,059,239 units
outstanding at December 31, 1999 and 1998, respectively) 208,359 253,568
Class B Common unitholders (1,307,190 units
outstanding at December 31, 1999) 20,548 -
Subordinated unitholders (10,029,619 units outstanding) (35,621) 15,995
General partner (313) 980
----------- ---------
192,973 270,543
----------- ---------
$ 1,223,037 $ 607,186
=========== =========
</TABLE>
See notes to consolidated and combined financial statements.
F-4
<PAGE>
<TABLE>
<CAPTION>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
Predecessor
---------------------------------
November 23, January 1,
Year Ended 1998 To 1998 To Year Ended
December 31, December 31, November 22, December 31,
1999 1998 1998 1997
-------------- --------------- --------------- ---------------
(restated) (restated)
<S> <C> <C> <C> <C>
REVENUES (restated) $ 4,739,892 $ 180,591 $ 1,011,734 $ 835,757
COST OF SALES AND OPERATIONS (restated) 4,629,578 173,092 980,753 823,277
UNAUTHORIZED TRADING LOSSES
AND RELATED EXPENSES (Note 3) 166,440 2,400 4,700 -
-------------- --------------- --------------- ---------------
Gross Margin (56,126) 5,099 26,281 12,480
-------------- --------------- --------------- ---------------
EXPENSES
General and administrative 23,211 771 4,526 3,529
Depreciation and amortization 17,344 1,192 4,179 1,165
Restructuring expense 1,410 - - -
-------------- --------------- --------------- ---------------
Total expenses 41,965 1,963 8,705 4,694
-------------- --------------- --------------- ---------------
Operating income (loss) (97,078) 3,136 17,576 7,786
Interest expense (20,533) (1,371) (8,492) (894)
Related party interest expense (606) - (2,768) (3,622)
Gain on sale of linefill (Note 5) 16,457 - - -
Interest and other income 958 12 572 138
-------------- --------------- --------------- ---------------
Net income (loss) before provision in lieu
of income taxes and extraordinary item (101,815) 1,777 6,888 3,408
Provision in lieu of income taxes - - 2,631 1,268
-------------- --------------- --------------- ---------------
Net income (loss) before extraordinary item (101,815) 1,777 4,257 2,140
Extraordinary item (Note 9) (1,545) - - -
-------------- --------------- --------------- ---------------
NET INCOME (LOSS) $ (103,360) $ 1,777 $ 4,257 $ 2,140
============== =============== =============== ===============
NET INCOME (LOSS) - LIMITED PARTNERS $ (101,517) $ 1,741 $ 4,172 $ 2,097
============== =============== =============== ===============
NET INCOME (LOSS) - GENERAL PARTNER $ (1,843) $ 36 $ 85 $ 43
============== =============== =============== ===============
BASIC AND DILUTED INCOME (LOSS)
PER LIMITED PARTNER UNIT
Net income (loss) before extraordinary item $ (3.16) $ 0.06 $ 0.25 $ 0.12
Extraordinary item (0.05) - - -
-------------- --------------- --------------- ---------------
Net income (loss) $ (3.21) $ 0.06 $ 0.25 $ 0.12
============== =============== =============== ===============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING 31,633 30,089 17,004 17,004
============== =============== =============== ===============
</TABLE>
See notes to consolidated and combined financial statements.
F-5
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Predecessor
--------------------------------
November 23, January 1,
Year Ended 1998 To 1998 To Year Ended
December 31, December 31, November 22, December 31,
1999 1998 1998 1997
--------------- --------------- ---------------- --------------
(restated) (restated)
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (103,360) $ 1,777 $ 4,202 $ 2,140
Items not affecting cash flows
from operating activities:
Depreciation and amortization 17,344 1,192 4,179 1,165
(Gain) loss on sale of assets (Note 5) (16,457) - 117 (28)
Change in payable in lieu of deferred taxes - - 2,231 1,131
Noncash compensation expense 1,013 - - -
Other non cash items 1,047 45 - -
Change in assets and liabilities, net of acquisition:
Accounts receivable and other (224,181) (10,245) 37,498 (10,454)
Inventory 34,772 (14,805) (3,336) (16,450)
Accounts payable and other current liabilities 164,783 36,675 (25,850) 9,627
Pipeline linefill (3) (6,247) 2,343 -
Other long-term liabilities and deferred credits 18,873 - - -
------------ -------- -------- --------
Net cash provided by (used in) operating activities (106,169) 8,392 21,384 (12,869)
------------ -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Costs incurred in connection with
acquisitions (Note 4) (176,918) - (394,026) -
Additions to property and equipment (12,801) (2,887) (5,528) (678)
Disposals of property and equipment 294 - 8 85
Additions to other assets (68) (202) (65) (1,261)
Proceeds from linefill sale (Note 5) 3,400 - - -
------------ -------- -------- --------
Net cash used in investing activities (186,093) (3,089) (399,611) (1,854)
------------ -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from (payments to) affiliates 34,924 (1,174) 3,349 (3,679)
Proceeds from issuance of units, net 76,450 241,690 - -
Distributions upon formation - (241,690) - -
Costs incurred in connection
with financing arrangements (17,243) - (9,938) -
Cash balance at formation - 224 - -
Proceeds from subordinated notes - general partner 114,000 - - -
Proceeds from long-term debt 403,721 - 331,300 -
Proceeds from short-term debt 131,119 1,150 30,600 39,000
Principal payments of long-term debt (268,621) - (39,300) -
Principal payments of short-term debt (82,150) - (40,000) (21,000)
Capital contribution from Parent - - 113,700 -
Dividend to Parent - - (3,557) -
Distributions to unitholders (51,673) - - -
------------- ------- ------- --------
Net cash provided by financing activities 340,527 200 386,154 14,321
------------- ------- ------- --------
Net increase (decrease) in cash
and cash equivalents 48,265 5,503 7,927 (402)
Cash and cash equivalents, beginning of period 5,503 - 2 404
------------- ------- ------- --------
Cash and cash equivalents, end of period $ 53,768 $ 5,503 $ 7,929 $ 2
============= ======= ======= ========
</TABLE>
See notes to consolidated and combined financial statements.
F-6
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998
AND THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
TOTAL
CLASS B GENERAL PARTNERS'
COMMON UNITS COMMON UNITS SUBORDINATED UNITS PARTNER CAPITAL
-------------------- ------------------ -------------------- --------- ----------
UNITS AMOUNT UNITS AMOUNT UNITS AMOUNT AMOUNT AMOUNT
------- --------- ------ -------- ------- --------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Issuance of units to public 13,085 $ 241,690 - $ - - $ - $ - $ 241,690
Contribution of assets and
debt assumed 6,974 106,392 - - 10,030 153,005 9,369 268,766
Distribution at time of
formation - (95,675) - - - (137,590) (8,425) (241,690)
Net income for the period
from November 23, 1998
to December 31, 1998 (restated) - 1,161 - - - 580 36 1,777
------- --------- ------ -------- ------- --------- --------- ----------
Balance at
December 31, 1998 (restated) 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
Distributions - (33,265) - (1,234) (15,915) (1,259) (51,673)
Net loss - (62,598) - (3,218) (35,701) (1,843) (103,360)
------- --------- ------ -------- ------- --------- --------- ----------
Balance at December 31, 1999 23,049 $ 208,359 1,307 $ 20,548 10,030 $ (35,621) $ (313) $ 192,973
======= ========= ====== ======== ======= ========= ========= ==========
</TABLE>
See notes to consolidated and combined financial statements.
F-7
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 1 -- Organization and Basis of Presentation
Organization
We are a Delaware limited partnership that was 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 the midstream subsidiaries of Plains Resources,
also referred to as our predecessor or the Plains Midstream Subsidiaries. Our
operations are conducted through Plains Marketing, L.P., All American Pipeline,
L.P. and Plains Scurlock Permian, L.P. Our general partner, Plains All American
Inc., is a wholly-owned subsidiary of Plains Resources. We are engaged in
interstate and intrastate marketing, transportation and terminalling of crude
oil. Terminals are facilities where crude oil is transferred to or from storage
or a transportation system, such as trucks or another pipeline. The operation of
these facilities is called "terminalling." Our operations are conducted
primarily in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
Formation and Offering
On November 23, 1998, we completed an initial public offering of 13,085,000
common units at $20.00 per unit, representing limited partner interests and
received net proceeds of approximately $244.7 million. Concurrently with the
closing of the initial public offering, certain of the Plains Midstream
subsidiaries were merged into Plains Resources, which sold the assets of these
subsidiaries to us in exchange for $64.1 million and the assumption of $11.0
million of related indebtedness. At the same time, our general partner conveyed
all of its interest in the All American Pipeline and the SJV Gathering System to
us in exchange for:
. 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2%
general partner interest;
. the right to receive incentive distributions as defined in the partnership
agreement; and
. our assumption of $175.0 million of indebtedness incurred by our general
partner in connection with the acquisition of the All American Pipeline and
the SJV Gathering System.
In addition to the $64.1 million discussed above, we distributed approximately
$177.6 million of the offering proceeds to our general partner and used
approximately $3.0 million of the remaining proceeds to pay expenses incurred in
connection with the initial public offering.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our
consolidated financial position as of December 31, 1999 and 1998, and the
results of our operations, cash flows and changes in partners' capital for the
year ended December 31, 1999 and the period from inception (November 23, 1998)
to December 31, 1998, and the results of operations and cash flows of our
predecessor for the period from January 1, 1998 to November 22, 1998 and the
year ended December 31, 1997. All significant intercompany transactions have
been eliminated. We have restated Revenues and Costs of Sales and Operations to
appropriately reflect certain transactions with Plains Resources. Certain
reclassifications have been made to prior period amounts to conform with 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 management 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. Although management believes 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 typically occurs
upon receipt of the product by the purchaser, and purchases are accrued at the
time title to the product purchased transfers to us, which typically occurs upon
our receipt of the product. Terminalling and storage revenues are recognized at
the time service is performed. Revenues for the transportation of crude oil are
recognized based upon regulated and non-regulated tariff rates and the related
transported volumes. Crude oil exchanges whereby like volumes are purchased and
sold with the same customers with little effect on gross margin are netted in
cost of sales and operations.
F-8
<PAGE>
Cost of Sales and Operations. Cost of sales consists of the cost of crude oil,
transportation 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 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.
Inventory. Inventory consists of crude oil in pipelines and in storage tanks
which is valued at the lower of cost or market, with cost determined using the
average cost method. Inventory at December 31, 1999 includes approximately $37.9
million of crude oil linefill which we began selling in November 1999 (see
Note 5).
Property and Equipment and Pipeline Linefill. Property and equipment is stated
at cost and consists of:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1999 1998
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Crude oil pipelines $ 351,460 $ 268,219
Crude oil pipeline facilities 39,358 70,870
Crude oil storage and terminal facilities 43,583 34,606
Trucking equipment, injection stations
and other 18,249 4,559
Office property and equipment 2,228 581
--------- ---------
454,878 378,835
Less accumulated depreciation and
amortization (11,581) (799)
--------- ---------
$ 443,297 $ 378,036
========= =========
</TABLE>
Depreciation is computed using the straight-line method over estimated useful
lives as follows:
. crude oil pipelines - 40 years;
. crude oil pipeline facilities - 25 years;
. crude oil terminal and storage facilities - 30 to 40 years;
. trucking equipment, injection stations and other - 5 to 10 years; and
. other property and equipment - 5 to 7 years.
Acquisitions and improvements are capitalized; maintenance and repairs are
expensed as incurred. Net gains or losses on property and equipment disposed of
are included in interest and other income.
Pipeline linefill is recorded at cost and consists of 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. After the sale of linefill discussed
below, we own approximately 1.2 million barrels of crude oil that is used to
maintain the vast majority of 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 and combined
statements of cash flows. Proceeds from the sale of linefill in connection with
the segment of the All American Pipeline that is being sold are included in
investing activities in the accompanying consolidated and combined statements of
cash flows. In November 1999, we initiated the sale of 5.2 million barrels of
crude oil linefill (see Note 5).
Impairment of Long-Lived Assets. Long-lived assets, including any related
goodwill, 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.
F-9
<PAGE>
Other Assets. Other assets consist of the following (in thousands):
DECEMBER 31,
-------------------------
1999 1998
--------- ---------
Debt issue costs $ 24,776 $ 10,171
Goodwill and other 1,994 1,134
--------- ---------
26,770 11,305
Accumulated amortization (3,663) (495)
--------- ---------
$ 23,107 $ 10,810
========= =========
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. Debt issue costs at December
31, 1999, include approximately $13.7 million paid to amend our credit
facilities as a result of defaults caused by unauthorized trading losses (see
Note 3). Goodwill was recorded as the amount of the purchase price in excess of
the fair value of certain transportation and crude oil gathering assets
purchased by our predecessor and is amortized using the straight-line method
over a period of twenty years.
Federal Income Taxes. No provision for income taxes related to our operations
is included in the accompanying consolidated financial statements because as a
partnership, we are not subject to federal or state 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 his/her 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 his/her 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, management does
not believe that in our circumstances, the aggregate difference would be
meaningful information.
Our predecessor is included in the consolidated federal income tax return of
Plains Resources. Income taxes are calculated as if our predecessor had filed a
return on a separate company basis utilizing a federal statutory rate of 35%.
Hedging. We utilize various derivative instruments, for purposes other than
trading, to hedge our exposure to price fluctuations on crude in storage and
expected purchases, sales and transportation of crude oil. The derivative
instruments consist primarily of futures and option contracts traded on the New
York Mercantile Exchange and crude oil swap contracts entered into with
financial institutions. We also utilize interest rate swaps and collars to
manage the interest rate exposure on our long-term debt.
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. Additionally, the derivatives result in financial impacts which 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. If correlation ceases to
exist, 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.
Unrealized changes in the market value of crude oil hedge contracts are not
generally recognized in our statement of operations or our predecessor's
statements of operations until the underlying hedged transaction occurs. The
financial impacts of crude oil hedge contracts are included in our and our
predecessor's 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 crude oil hedging activities are included in operating
activities in the accompanying statements of cash flows. Net deferred gains and
losses on futures contracts, including closed futures contracts, entered into to
hedge anticipated crude oil 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 long-term debt being hedged, resulting in an adjustment to the
effective interest rate. Deferred gains of $10.8 million received upon the
termination of an interest rate swap are included in other long-term liabilities
and deferred credits, net of accumulated amortization, in the accompanying
balance sheet at December 31, 1999.
F-10
<PAGE>
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
our general partner, by the weighted average number of outstanding common units
and subordinated units. Partnership income (loss) is allocated first according
to cash distributions, and the remainder according to percentage ownership in
the partnership. For periods prior to November 23, 1998, outstanding units are
assumed to equal the common and subordinated units received by our general
partner in exchange for assets contributed to us.
Unit Options. We have elected to follow Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to Employees ("APB 25") and related
interpretations in accounting for our employee unit options and awards. Under
APB 25, no compensation expense is recognized when the exercise price of options
equals the fair value (market price) of the underlying units on the date of
grant (see Note 14).
Recent Accounting Pronouncements. In June 1998, the FASB issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities ("SFAS 133"). SFAS 133 requires that all derivative
instruments be recorded on the balance sheet 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 an asset's, liability's,
or firm commitment's fair value, changes in the fair value of the derivative
instrument will generally be offset in the income statement by changes in the
hedged item's fair value. 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. 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. This statement
was amended by Statement of Financial Accounting Standards No. 137, Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers
the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. We
are required to adopt this statement beginning in 2001. We have not yet
determined the effect that the adoption of SFAS 133 will have on our financial
position or results of operations.
NOTE 3 -- UNAUTHORIZED TRADING LOSSES AND RESTATED FINANCIAL STATEMENTS
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,
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.
Normally, as we purchase crude oil, we establish a margin by selling crude oil
for physical delivery to third-party users or by entering into a future delivery
obligation with respect to futures contracts. The employee in question violated
our policy of maintaining a position that is substantially balanced between
crude oil purchases and sales or future delivery obligations. The unauthorized
trading and associated losses resulted in a default of certain covenants under
our credit facilities and significant short-term cash and letter of credit
requirements.
In December 1999, we executed amended credit facilities and obtained default
waivers from all of our lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit
facilities;
. increased availability under our letter of credit and borrowing facility
from $175.0 million in November 1999 to $295.0 million in December 1999,
$315.0 million in January 2000, and thereafter decreasing to $239.0 million
in February through April 2000, to $225.0 million in May and June 2000 and
to $200.0 million in July 2000 through July 2001;
. required the lenders' consent prior to the payment of distributions to
unitholders;
. prohibited contango inventory transactions subsequent to January 20, 2000;
and
. increased interest rates and fees under certain of the facilities.
We paid approximately $13.7 million to our lenders in connection with the
amended credit facilities. This amount was capitalized as debt issue costs and
will be amortized over the remaining term of the amended facilities. In
connection with the amendments, our general partner loaned us approximately
$114.0 million. This subordinated debt is due not later than November 30, 2005.
F-11
<PAGE>
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 the amended 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, certain of our purchase contracts were terminated.
The summarized restated results for the periods ended and financial position
as of March 31, June 30, and September 30, 1999 are as follows: (in thousands,
except unit data) (unaudited).
RESTATED
--------------------------------------------------------
THREE PERIOD ENDED PERIOD ENDED
MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999
ENDED -------------------- ----------------------
MARCH 31, THREE SIX THREE NINE
1999 MONTHS MONTHS MONTHS MONTHS
--------- -------- --------- --------- ----------
STATEMENT OF
OPERATIONS DATA:
Gross margin $ (1,546) $ 4,985 $ 3,439 $ (38,922) $ (35,483)
Operating loss (6,965) (4,624) (11,589) (51,892) (63,481)
Net loss (10,061) (9,154) (19,215) (60,131) (79,346)
Net loss per limited
partner unit (0.33) (0.29) (0.62) (1.88) (2.53)
BALANCE SHEET DATA:
Current assets $186,846 $ 413,418 $ 522,332
Current liabilities 190,331 452,307 622,394
Partners' capital 261,657 263,939 190,877
CASH FLOW DATA:
Net cash provided by
operating activities $ 4,445 $ 15,397 $ 1,380
The summarized previously reported results for the periods ended and financial
position as of March 31, June 30, and September 30, 1999 are as follows: (in
thousands, except unit data) (unaudited).
PREVIOUSLY REPORTED
--------------------------------------------------------
THREE PERIOD ENDED PERIOD ENDED
MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999
ENDED -------------------- ----------------------
MARCH 31, THREE SIX THREE NINE
1999 MONTHS MONTHS MONTHS MONTHS
--------- -------- --------- --------- ----------
STATEMENT OF
OPERATIONS DATA:
Gross margin $ 19,828 $ 26,212 $ 46,040 $ 33,304 $ 79,344
Operating income 14,409 16,603 31,422 20,334 51,346
Net income 11,313 12,073 23,386 12,095 35,481
Net income per limited
partner unit 0.37 0.38 0.75 0.38 1.13
BALANCE SHEET DATA:
Current assets $187,015 $ 413,344 $522,234
Current liabilities 169,126 409,632 507,469
Partners' capital 283,031 306,540 305,704
CASH FLOW DATA:
Net cash provided by
operating activities $ 4,276 $ 15,471 $ 1,478
Below is the summarized restated and previously reported results for the three
and nine months ending September 30, 1998 (in thousands, except unit data)
(unaudited).
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 1998 SEPTEMBER 30, 1998
------------------- -------------------
PREVIOUSLY PREVIOUSLY
RESTATED REPORTED RESTATED REPORTED
-------- ---------- -------- ----------
STATEMENT OF
OPERATIONS DATA:
Gross margin $ 6,914 $13,914 $16,114 $23,114
Operating income 3,410 10,410 9,948 16,948
Net income (loss) (1,212) 3,258 2,042 6,512
Net income (loss) per
limited partner unit (0.07) 0.19 0.12 0.38
F-12
<PAGE>
The summarized restated and previously reported results for the periods of
November 23, 1998 to December 31, 1998 and January 1, 1998 to November 22, 1998
and financial position as of Decvember 31, 1998 are as follows (in thousands,
except unit data):
November 23, 1998 January 1, 1998
to December 31, 1998 to November 22, 1998
-------------------- --------------------
Previously Previously
Restated Reported Restated Reported
-------- --------- -------- ----------
Statement of Operations Data:
Gross margin $ 5,099 $ 7,499 $ 26,281 $ 30,981
Operating income 3,136 5,536 17,576 22,276
Net income 1,777 4,177 4,257 7,025
Net income per limited partner unit 0.06 0.14 0.25 0.40
Balance Sheet Data:
Current assets $ 163,829 $ 166,851 $ - $ -
Current liabilities 161,598 157,520 - -
Partners' capital 270,543 277,643 - -
NOTE 4 -- ACQUISITIONS
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.
Scurlock, previously a wholly-owned subsidiary of Marathon Ashland Petroleum,
is engaged in crude oil transportation, gathering and marketing, and owns
approximately 2,300 miles of active pipelines, numerous storage terminals and a
fleet of more than 250 trucks. Its largest asset is an 800-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.
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's limited
recourse bank facility with BankBoston, N.A.;
. the sale to our 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 existing revolving credit agreement.
The purchase price allocation was based on preliminary estimates of fair value
and is subject to adjustment as additional information becomes available and is
evaluated. 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 to Plains Scurlock, Marathon Ashland
Petroleum has agreed to indemnify and hold harmless Scurlock and Plains Scurlock
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 Scurlock against Marathon
Ashland Petroleum on or before May 15, 2003.
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 Accounting Principles Board
Opinion No. 16, Business Combinations, ("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
========
F-13
<PAGE>
West Texas Gathering System Acquisition
On July 15, 1999, Plains Scurlock Permian, L.P. 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, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for
the amounts paid at closing was provided by a draw under the term loan portion
of the Plains Scurlock credit facility.
Pro Forma Results for the Scurlock and West Texas Gathering System Acquisitions
The following unaudited pro forma data is presented to show pro forma
revenues, net income (loss) and basic and diluted net income (loss) per limited
partner unit as if the Scurlock and West Texas Gathering System acquisitions
had occurred on January 1, 1998 (in thousands):
YEAR NOVEMBER 23, JANUARY 1,
ENDED 1998 TO 1998 TO
DECEMBER 31, DECEMBER 31, NOVEMBER 22,
1999 1998 1998
----------- --------- -----------
(restated) (restated)
Revenues (restated) $ 5,130,961 $ 283,251 $ 2,165,441
=========== ========= ===========
Net income (loss) $ (97,501) $ (8,080) $ 936
=========== ========= ===========
Basic and diluted net income (loss)
per limited partner unit $ (3.02) $ (0.25) $ 0.05
=========== ========= ===========
Venice Terminal Acquisition
On September 3, 1999, we completed the acquisition of a Louisiana crude oil
terminal facility and associated pipeline system from Marathon Ashland Petroleum
LLC for approximately $1.5 million. The principal assets acquired include
approximately 300,000 barrels of crude oil storage and terminalling capacity and
a six-mile crude oil transmission system near Venice, Louisiana.
All American Pipeline Acquisition
On July 30, 1998, our predecessor acquired all of the outstanding capital
stock of the All American Pipeline Company, Celeron Gathering Corporation and
Celeron Trading & Transportation Company (collectively the "Celeron
Companies") from Wingfoot, a wholly-owned subsidiary of the Goodyear Tire and
Rubber Company ("Goodyear"), for approximately $400.0 million, including
transaction costs. The principal assets of the entities acquired include the All
American Pipeline and the SJV Gathering System, as well as other assets related
to such operations. The acquisition was accounted for utilizing the purchase
method of accounting with the assets, liabilities and results of operations
included in the combined financial statements of the predecessor effective
July 30, 1998.
The acquisition was accounted for utilizing 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 $ 392,528
Other assets (debt issue costs) 6,138
Net working capital items (excluding cash received of $7,481) 1,498
---------
Cash paid $ 400,164
=========
Financing for the acquisition was provided through a $325.0 million, limited
recourse bank facility and an approximate $114.0 million capital contribution by
Plains All American Inc. Actual borrowings at closing were $300.0 million.
In 1999, we terminated 24 employees and paid approximately $1.4 million in
connection therewith.
F-14
<PAGE>
NOTE 5 -- ASSET DISPOSITIONS
We initiated the sale of approximately 5.2 million barrels of crude oil
linefill from the All American Pipeline in November 1999. This sale was
substantially completed in February 2000. The linefill was located in the
segment of the All American Pipeline that extends from Emidio, California, to
McCamey, Texas. Except for minor third party volumes, Plains Marketing, L.P.,
one of our subsidiaries, has been the sole shipper on this segment of the
pipeline since its predecessor acquired the line from Goodyear on July 30, 1998.
Proceeds from the sale of the linefill were approximately $100.0 million, net of
associated costs, and were used for working capital purposes. We estimate that
we will recognize a total gain of approximately $44.6 million in connection with
the sale of linefill. As of December 31, 1999, we had delivered approximately
1.8 million barrels of linefill and recognized a gain of $16.5 million. The
amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and
is included in assets held for sale on the consolidated balance sheet.
On March 24, 2000, we completed the sale of the above referenced segment of
the All American Pipeline to a unit of El Paso Energy Corporation for total
proceeds of $129.0 million. The proceeds from the sale were used to reduce
outstanding debt. Our net proceeds are expected to be approximately $124.0
million, net of associated transaction costs and estimated costs to remove
certain equipment. We estimate that we will recognize a gain of approximately
$20.0 million in connection with the sale. During 1999, we reported gross margin
of approximately $5.0 million from volumes transported on the segment of the
line that was sold. The cost of the pipeline segment is included in assets held
for sale on the consolidated balance sheet at December 31, 1999.
NOTE 6 --CREDIT AGREEMENTS AND LONG-TERM DEBT
Short-term debt and current portion of long-term debt consists of the
following:
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- -----------
(in thousands)
<S> <C> <C>
Letter of credit borrowing facility, bearing interest at
weighted average interest rates of 8.7% and 6.8%
at December 31, 1999 and 1998, respectively $ 13,719 $ 9,750
Secured term credit facility, bearing interest at
a weighted average interest rate of 8.8%
at December 31, 1999 45,000 -
-------- -------
58,719 9,750
Current portion of long-term debt 50,650 -
-------- -------
$109,369 $ 9,750
======== =======
</TABLE>
We have a 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 for resale and borrowings to finance crude oil inventory which has been
hedged against future price risk or designated as working inventory. As a result
of the unauthorized trading losses discovered in November 1999, the facility was
in default of certain covenants, with those defaults being subsequently waived
and the facility amended in December 1999. As amended, the letter of credit
facility has a sublimit for cash borrowings of $40.0 million at December 31,
1999, with decreasing amounts thereafter through April 30, 2000, at which time
the sublimit is eliminated. The letter of credit and borrowing facility provides
for an aggregate letter of credit availability of $295.0 million in December
1999, $315.0 million in January 2000, and thereafter decreasing to $239.0
million in February through April 2000, to $225.0 million in May and June 2000
and to $200.0 million in July 2000 through July 2001. Aggregate availability
under the letter of credit facility for direct borrowings and letters of credit
is limited to a borrowing base which is determined monthly based on certain of
our current assets and current liabilities, primarily accounts receivable and
accounts payable related to the purchase and sale of crude oil. This facility is
secured by a lien on substantially all of our assets except the assets which
secure the Plains Scurlock credit facility. At December 31, 1999, there were
letters of credit of approximately $292.0 million and borrowings of $13.7
million outstanding under this facility.
On December 30, 1999, we entered into a $65.0 million senior secured term
credit facility to fund short-term working capital requirements resulting from
the unauthorized trading losses. The facility was secured by a portion of the
5.2 million barrels of linefill that was sold and receivables from certain sales
contracts applicable to the linefill. The facility had a maturity date of March
24, 2000 and was repaid with the proceeds from the sale of the linefill securing
the facility. At December 31, 1999, there were borrowings of $45.0 million
outstanding.
F-15
<PAGE>
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1999 1998
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
All American Pipeline, L.P. bank credit agreement,
bearing interest at weighted average interest rates of 8.3%
and 6.8% at December 31, 1999 and 1998, respectively $ 225,000 $ 175,000
Plains Scurlock bank credit agreement, bearing interest at
a weighted average interest rate of 9.1% at December 31, 1999 85,100 -
Subordinated note payable - general partner, bearing interest at
a weighted average interest rate of 8.7% at December 31, 1999 114,000 -
--------- ---------
424,100 175,000
Less current maturities (50,650) -
--------- ---------
$ 373,450 $ 175,000
========= =========
</TABLE>
Concurrently with the closing of our initial public offering in November 1998,
we entered into a $225.0 million bank credit agreement that includes a $175.0
million term loan facility and a $50.0 million revolving credit facility. As a
result of the unauthorized trading losses discovered in November 1999, the
facility was in default of certain covenants, with those defaults being
subsequently waived and the facility amended in December. The bank credit
agreement is secured by a lien on substantially all of our assets except the
assets which secure the Plains Scurlock bank credit agreement. We may borrow up
to $50.0 million under the revolving credit facility for acquisitions, capital
improvements, working capital and general business purposes. At December 31,
1999, we had $175.0 million outstanding under the term loan facility and $50.0
million outstanding under the revolving credit facility. The term loan facility
matures in 2005, and no principal is scheduled for payment prior to maturity.
The term loan facility may be prepaid at any time without penalty. The revolving
credit facility expires in November 2000. The term loan and revolving credit
facility bear interest at our option at either the base rate, as defined, plus
an applicable margin, or reserve adjusted LIBOR plus an applicable margin. We
incur a commitment fee on the unused portion of the revolving credit facility.
Plains Scurlock has a bank credit agreement which consists of a five-year
$82.6 million term loan facility and a three-year $35.0 million revolving credit
facility. The Plains Scurlock bank credit agreement is nonrecourse to Plains All
American Pipeline, Plains Marketing, L.P. and All American Pipeline, L.P. and is
secured by substantially all of the assets of Plains Scurlock Permian, L.P. and
its subsidiaries, including the Scurlock assets and the West Texas gathering
system. Borrowings under the term loan and the revolving credit facility bear
interest at LIBOR plus the applicable margin. A commitment fee equal to 0.5% per
year is charged on the unused portion of the revolving credit facility. The
revolving credit facility, which may be used for borrowings or letters of credit
to support crude oil purchases, matures in May 2002. The term loan provides for
principal amortization of $0.7 million annually beginning May 2000, with a final
maturity in May 2004. As of December 31, 1999, letters of credit of
approximately $29.5 million were outstanding under the revolver and borrowings
of $82.6 million and $2.5 million were outstanding under the term loan and
revolver, respectively. The term loan was reduced to $82.6 million from $126.6
million with proceeds from our October 1999 public unit offering.
All of our credit facilities contain prohibitions on distributions on, or
purchases or redemptions of, units if any default or event of default is
continuing. In addition, our facilities contain various covenants limiting our
ability to:
. incur indebtedness;
. grant liens;
. sell assets in excess of certain limitations;
. engage in transactions with affiliates;
. make investments;
. enter into hedging contracts; and
. enter into a merger, consolidation or sale of assets.
Each of our facilities treats a change of control as an event of default. In
addition, the terms of our letter of credit and borrowing facility and our bank
credit agreement require lenders' consent prior to the payment of distributions
to unitholders and require us to maintain:
. a current ratio of 1.0 to 1.0, as defined in our credit agreement;
. a debt coverage ratio which is not greater than 5.0 to 1.0;
F-16
<PAGE>
. an interest coverage ratio which is not less than 3.0 to 1.0;
. a fixed charge coverage ratio which is not less than 1.25 to 1.0; and
. debt to capital ratio of not greater than 0.60 to 1.0.
The terms of the Plains Scurlock bank credit agreement requires Plains
Scurlock to maintain at the end of each quarter:
. a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June 30,
2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to 1.0
thereafter; and
. an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through
June 30, 2000 and 2.5 to 1.0 thereafter.
In addition, the Plains Scurlock bank credit agreement contains limitations on
the Plains Scurlock operating partnership's ability to make distributions to us
if its indebtedness and current liabilities exceed certain levels as well as the
amount of expansion capital it may expend.
In December 1999, our general partner loaned us $114.0 million. This
subordinated debt is due not later than November 30, 2005. Proceeds from the
notes were used for working capital requirements created by the unauthorized
trading losses (see Note 3). The notes are subordinated in right of payment to
all existing senior indebtedness and bear interest at the same LIBOR rate as our
letter of credit and borrowing facility. Interest on the notes is payable
monthly, but payment of interest requires the permission of certain of our
lenders. Any interest not paid when due is added to the principal of the notes,
at the option of our general partner.
At December 31, 1999, we had interest rate collar agreements aggregating a
notional principal amount of $215.0 million which hedge the interest rate on our
underlying debt obligations. These instruments are based on LIBOR rates before
the applicable margins and generally provide for a floor of 5% and a ceiling of
6.5% for $90.0 million of debt and a floor of 6.1% and a ceiling of 8% for
$125.0 million of debt.
Maturities
The aggregate amount of maturities of all long-term indebtedness for the next
five years is: 2000 - $50.6 million, 2001 - $0.6 million, 2002 - $3.2 million,
2003 - $0.7 million and 2004 - $80.0 million.
NOTE 7 -- PARTNERSHIP CAPITAL AND DISTRIBUTIONS
Partner's capital consists of 24,356,429 common units, including 1,307,190
Class B common units, representing a 69.4% limited partner interest, (a
subsidiary of our general partner owns 6,904,795 of such common units),
10,029,619 Subordinated units owned by a subsidiary of our general partner
representing a 28.6% limited partner interest and a 2% general partner interest.
In the aggregate, our general partner's interests represent an effective 54.0%
ownership of our equity at December 31, 1999.
All of the subordinated units and 20,059,239 of the common units were issued
in connection with our November 1998 initial public offering. In October 1999,
we completed a public offering of an additional 2,990,000 common units
representing limited partner interests at $18.00 per unit. Net proceeds,
including our general partners' contribution, from the offering were
approximately $51.3 million after deducting underwriters' discounts and
commissions and offering expenses of approximately $3.1 million. These proceeds
were used to reduce outstanding debt. The Class B common units were issued in
May 1999 to our general partner at $19.125 per unit for total proceeds of $25.0
million in connection with the Scurlock acquisition (see Note 4).
Subject to the consent of our lenders, 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 subordinated period (which will not end earlier than
December 31, 2003) and to receive any arrearages in the distribution of the MQD
on the common units for the prior quarters during the subordinated period. The
MQD is $0.45 per unit ($1.80 per unit on an annual basis). Upon expiration of
the subordination period, all subordinated units will be converted on a one-for-
one basis into common units and will participate pro rata with all other common
units in future distributions of available cash. Under certain circumstances, up
to 50% of the subordinated units may convert into common units prior to the
expiration of the subordination period. 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.
If quarterly distributions of available cash exceed the MQD or the Target
Distribution Levels (as defined), our general partner will receive distributions
which are generally equal to 15%, then 25% and then 50% of the distributions of
available
F-17
<PAGE>
cash that exceed the MQD or Target Distribution Level. The Target Distribution
Levels are based on the amounts of available cash from our Operating Surplus (as
defined) distributed with respect to a given quarter that exceed distributions
made with respect to the MQD and common unit arrearages, if any.
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.
Our 1999 and 1998 distributions declared, which were paid in the quarter
following declaration are summarized in the following table:
<TABLE>
<CAPTION>
DISTRIBUTION PER UNIT TOTAL DISTRIBUTION
----------------------- --------------------------------------------------
COMMON SUBORDINATED GENERAL
COMMON SUBORDINATED UNITHOLDERS UNITHOLDERS PARTNER TOTAL
------- ------------ ----------- ------------ ------- -----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
1999
Fourth quarter $ 0.450 $ - $10,960 $ - $ 224 $11,184
Third quarter 0.481 0.481 11,721 4,827 506 17,054
Second quarter 0.463 0.463 9,881 4,639 358 14,878
First quarter 0.450 0.450 9,026 4,513 276 13,815
1998
Fourth quarter $ 0.193 $ 0.193 $ 3,871 $ 1,936 $ 119 $ 5,926
</TABLE>
The fourth quarter 1998 distribution represents a partial quarterly
distribution for the period from November 23, 1998, the date of our initial
public offering, to December 31, 1998.
NOTE 8 -- FINANCIAL INSTRUMENTS
Derivatives
We utilize derivative financial instruments to hedge our exposure to price
volatility on crude oil and do not use such instruments for speculative trading
purposes. These arrangements expose us to credit risk (as to counterparties) and
to risk of adverse price movements in certain cases where our purchases are less
than expected. In the event of non-performance of a counterparty, we might be
forced to acquire alternative hedging arrangements or be required to honor the
underlying commitment at then-current market prices. In order to minimize credit
risk relating to the non-performance of a counterparty, we enter into such
contracts with counterparties that are considered investment grade, periodically
review the financial condition of such counterparties and continually monitor
the effectiveness of derivative financial instruments in achieving our
objectives. In view of our criteria for selecting counterparties, our process
for monitoring the financial strength of these counterparties and our experience
to date in successfully completing these transactions, we believe that the risk
of incurring significant financial statement loss due to the non-performance of
counterparties to these transactions is minimal.
At December 31, 1999, our hedging activities included crude oil futures
contracts maturing in 2000 through 2002, covering approximately 7.4 million
barrels of crude oil including the portion of the linefill sold in January and
February 2000. Since 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.
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.
Crude oil futures contracts permit settlement by delivery of the crude oil and,
therefore, are not financial instruments. The carrying value of bank debt
approximates fair value as interest rates are variable, based on prevailing
market rates. The fair value of crude oil and interest rate swap and collar
agreements are based on current termination values or quoted market prices of
comparable contracts.
F-18
<PAGE>
We utilize interest rate swap and collar agreements to hedge the interest rate
on our underlying debt obligations. The carrying amounts and fair values of our
financial instruments are as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------
1999 1998
----------------- ------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------ -------- -------
<S> <C> <C> <C> <C>
Unrealized loss on crude oil swaps $ - $ (569) - $ -
Unrealized gain (loss) on interest rate swaps
and collars - 388 - (2,164)
</TABLE>
NOTE 9 -- EXTRAORDINARY ITEM
For the year ended December 31, 1999, we recognized a $1.5 million
extraordinary loss related to the early extinguishment of debt. The loss is
related to the reduction of the Plains Scurlock term loan facility with proceeds
from our 1999 public offering and the restructuring of our letter of credit and
borrowing facility as a result of the unauthorized trading losses (see Notes 3
and 7).
NOTE 10 -- INCOME TAXES
As discussed in Note 2, our predecessor's results are included in Plains
Resources' combined federal income tax return. The amounts presented below were
calculated as if our predecessor filed a separate tax return.
Provision in lieu of income taxes of our predecessor consists of the following
components (in thousands):
<TABLE>
<CAPTION>
JANUARY 1,
1998 TO YEAR ENDED
NOVEMBER 22, DECEMBER 31,
1998 1997
----------- ------------
(RESTATED)
<S> <C> <C>
Federal
Current $ 455 $ 38
Deferred 1,900 1,131
State
Current - 99
Deferred 276 -
------- -------
Total $ 2,631 $ 1,268
======= =======
</TABLE>
A reconciliation of the provision in lieu of income taxes to the federal
statutory tax rate of 35% is as follows (in thousands):
<TABLE>
<CAPTION>
JANUARY 1,
1998 TO YEAR ENDED
NOVEMBER 22, DECEMBER 31,
1998 1997
------------ ------------
(RESTATED)
<S> <C> <C>
Provision at the statutory rate $ 2,410 $ 1,169
State income tax, net of
benefit for federal deduction 181 65
Permanent differences 40 34
------------ ------------
Total $ 2,631 $ 1,268
============ ============
</TABLE>
F-19
<PAGE>
NOTE 11 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
In connection with our formation, certain investing and financial activities
occurred. Effective November 23, 1998, substantially all of the assets and
liabilities of our predecessor were conveyed to us at historical cost. Net
assets assumed by the operating partnership are as follows (restated) (in
thousands):
Cash and cash equivalents $ 224
Accounts receivable 109,311
Inventory 22,906
Prepaid expenses and other current assets 1,059
Property and equipment, net 375,948
Pipeline linefill 48,264
Intangible assets, net 11,001
---------
Total assets conveyed 568,713
---------
Accounts payable and other current liabilities 107,405
Due to affiliates 8,942
Bank debt 183,600
---------
Total liabilities assumed 299,947
---------
Net assets assumed by the Partnership $ 268,766
=========
Interest paid totaled $22.3 million, $0.1 million, $8.5 million and $4.5
million for the year ended December 31, 1999, the period from November 23, 1998
to December 31, 1998, the period from January 1, 1998 through November 23, 1998
and the year ended December 31, 1997, respectively.
NOTE 12 -- MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
Customers accounting for 10% or more of revenues were as follows for the
periods indicated:
<TABLE>
<CAPTION>
PERCENTAGE
-------------------------------------------------------------
NOVEMBER 23, JANUARY 1,
YEAR ENDED 1998 TO 1998 TO YEAR ENDED
DECEMBER 31, DECEMBER 31, NOVEMBER 22, DECEMBER 31,
CUSTOMER 1999 1998 1998 1997
--------------------------------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Sempra Energy Trading Corporation 22% 20% 31% 12%
Koch Oil Company 19% - 19% 30%
Exxon Company USA - 11% - -
Basis Petroleum Inc. - - - 11%
</TABLE>
Financial instruments which 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 generally require letters
of credit for receivables from customers which are not considered investment
grade, unless the credit risk can otherwise be reduced. We believe that the loss
of an individual customer would not have a material adverse effect.
NOTE 13 -- RELATED PARTY TRANSACTIONS
Reimbursement of Expenses 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 and Plains Resources.
Our general partner does not receive a management fee or other compensation in
connection with its management of us. We reimburse our general partner and
Plains Resources for all direct and indirect costs of services provided,
including the costs of employee, officer and director compensation and benefits
properly allocable to us, and all other expenses necessary or appropriate to the
conduct of the business of, and allocable to us. Our 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.
Total costs reimbursed to our general partner and Plains Resources by us were
approximately $44.7 million and $0.5 million for the year ended December 31,
1999 and for period from November 23, 1998
F-20
<PAGE>
to December 31, 1998, 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.
Plains Resources allocated certain general and administrative expenses to the
Plains Midstream Subsidiaries during 1998 and 1997. The types of indirect
expenses allocated to the Plains Midstream Subsidiaries during this period were
office rent, utilities, telephone services, data processing services, office
supplies and equipment maintenance. Direct expenses allocated by Plains
Resources were primarily salaries and benefits of employees engaged in the
business activities of the Plains Midstream Subsidiaries.
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. For the year ended
December 31, 1999 and the period from November 23, 1998 to December 31, 1998, we
paid Plains Resources approximately $131.5 million and $4.1 million,
respectively, for the purchase of crude oil under the agreement and recognized
profits of approximately $1.5 million and $0.1 million from the marketing fee
for the same periods, respectively. Prior to the marketing agreement, our
predecessor marketed crude oil production of Plains Resources, its subsidiaries
and its royalty owners. Our predecessor paid approximately $83.4 million and
$101.2 million for the purchase of these products for the period from January 1,
1998 to November 22, 1998 and the year ended December 31, 1997, respectively. In
management's opinion, these purchases were made at prevailing market prices. Our
predecessor did not recognize a profit on the sale of the crude oil purchased
from Plains Resources.
Financing
In December 1999, our general partner loaned us $114.0 million. This
subordinated debt is due not later than November 30, 2005 (see Note 6). Interest
expense related to the notes was $0.6 million for the year ended December 31,
1999.
To finance a portion of the purchase price of the Scurlock acquisition, we
sold to our 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 affiliates at December 31, 1999 and 1998 was
$42.7 million and $7.8 million, respectively, and was related to the
transactions discussed above.
Benefit Plan
Plains Resources maintains a 401(k) defined contribution plan whereby they
match 100% of an employee's contribution (subject to certain limitations in the
plan), with matching contribution 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 are granted). For the years ended December
31, 1999, 1998 and 1997, defined contribution plan expense for PAA was $0.7
million, $0.2 million and $0.1 million, respectively.
NOTE 14 -- LONG-TERM INCENTIVE PLANS
Our general partner has adopted the Plains All American Inc. 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 975,000 common units. The plan is administered by the
Compensation Committee of our general partner's board of directors.
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, 2000, an aggregate of approximately 500,000 restricted units have been
authorized for grants to employees of our general partner, 170,000 of which have
been granted with the remaining 330,000 to be granted in the near future. 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. In general, restricted units granted to employees during the
subordination period will vest only upon, 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 will be eligible to vest prior to
termination of the subordination period.
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, common units already owned by our general partner,
common units acquired by our general partner directly from us or any other
person, or any combination of the foregoing. Our general partner will be
entitled to reimbursement by us for the cost incurred in acquiring common units.
If we issue new common units upon vesting of the restricted units, the total
number of common
F-21
<PAGE>
units outstanding will increase. Following the subordination period, the
Compensation Committee, in its discretion, may grant tandem distribution
equivalent rights with respect to restricted units.
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, purchased directly from us or any other
person, or use 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 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.
We apply APB 25 and related interpretations in accounting for unit option
plans. In accordance with APB 25, no compensation expense has been recognized
for the unit option plan. Since no options have been granted to date, there is
no pro forma effect of a fair value based method of accounting in accordance
with Statement of Financial Accounting Standards No. 123 "Accounting for Stock-
Based Compensation" ("SFAS 123").
Transaction Grant Agreements. In addition to the grants made under the
Restricted Unit Plan described above, our general partner, at no cost to us,
agreed to transfer approximately 400,000 of its affiliates' common units
(including distribution equivalent rights attributable to such units) to certain
key employees of our general partner. A grant covering 50,000 of such common
units was terminated in 1999. Generally, approximately 69,444 of the remaining
common units vest in each of the years ending December 31, 1999, 2000 and 2001
if the operating surplus generated in such year equals or exceeds the amount
necessary to pay the minimum quarterly distribution on all outstanding common
units and the related distribution on our general partner interest. If a tranche
of common units does not vest in a particular year, such common units will vest
at the time the common unit arrearages for such year have been paid. In
addition, approximately 47,224 of the remaining common units vest in each of the
years ending December 31, 1999, 2000 and 2001 if the operating surplus generated
in such year exceeds the amount necessary to pay the minimum quarterly
distribution on all outstanding common units and subordinated units and the
related distribution on our general partner interest. In 1999, approximately
69,444 of such common units vested and 47,224 of such common units remain
unvested as no distribution on the subordinated units was made for the fourth
quarter of 1999. Any common units remaining unvested shall vest upon, and in the
same proportion as, the conversion of subordinated units to common units.
Distribution equivalent rights are paid in cash at the time of the vesting of
the associated common units. Notwithstanding the foregoing, all common units
become vested if Plains All American Inc. is removed as our general partner
prior to January 1, 2002.
We recognized noncash compensation expense of approximately $1.0 million for
the year ended December 31, 1999 related to the transaction grants which vested
in 1999. We reflected a capital contribution from our general partner for a like
amount. This amount is included in general and administrative expense on the
Consolidated Statements of Operations.
F-22
<PAGE>
NOTE 15 -- 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 whose contracts generally extend
beyond one year but can be canceled at any time should they not be required for
operations. Future non-cancelable commitments related to these items at December
31, 1999, are summarized below (in thousands):
2000 $ 7,484
2001 5,158
2002 1,706
2003 1,033
2004 933
Later years 1,528
Total lease expense incurred for 1999 was $8.9 million. Lease expense incurred
for the period from November 23, 1998 to December 31, 1998 and from January 1,
1998 to November 22, 1998 was $0.2 million and $0.9 million, respectively.
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 proposed extending the scope
of our study and are awaiting the state's response. We have spent approximately
$130,000 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. In addition, a portion of any such costs may be reimbursed to us from
Plains Resources.
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, et al. The suit alleged
that Plains All American Pipeline, L.P. and certain of our general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
have been filed in the Southern District of Texas, some of which name our
general partner and Plains Resources as additional defendants. Plaintiffs allege
that the defendants are 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.
The court has consolidated all subsequently filed cases under the first filed
action described above. Two unopposed motions are currently pending to appoint
lead plaintiffs. These motions ask the court to appoint two distinct lead
plaintiffs to represent two different plaintiff classes: (1) purchasers of
Plains Resources common stock and options and (2) purchasers of our common
units. Once lead plaintiffs have been appointed, the plaintiffs will file their
consolidated amended complaints. No answer or responsive pleading is due until
thirty days after a consolidated amended complaint is filed.
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 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 derivative complaints
allege, among other things, that Plains All American Pipeline has been harmed
due to the negligence or breach of loyalty of the officers and directors that
are named in the lawsuits. These cases are currently in the process of being
consolidated. No answer or responsive pleading is due until these cases have
been consolidated and a consolidated complaint has been filed.
We are a defendant, in the ordinary course of business, in various other legal
proceedings in which our exposure, individually and in the aggregate, is not
considered material to the accompanying financial statements.
F-23
<PAGE>
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.
NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
1999(1)
Revenues $ 471,209 $ 885,046 $1,127,808 $2,255,829 $4,739,892
Gross margin (1,546) 4,985 (38,922) (20,643) (56,126)
Operating loss (6,965) (4,624) (51,892) (33,597) (97,078)
Net loss (10,061) (9,154) (60,131) (24,014) (103,360)
Net loss per limited partner unit (0.33) (0.29) (1.88) (0.69) (3.21)
Cash distributions per common unit(2) $ 0.450 $ 0.463 $ 0.481 $ 0.450 $ 1.844
1998(1)
Revenues $ 184,180 $ 178,868 $ 440,941 $ 388,336 $1,192,325
Gross margin 4,004 5,196 6,914 15,266 31,380
Operating income 2,715 3,823 3,410 10,764 20,712
Net income (loss) 1,240 2,014 (1,212) 3,992 6,034
Net income (loss) per limited partner
unit 0.07 0.12 (0.07) 0.17 0.32
Cash distributions per common unit(2) $ -- $ -- $ -- $ 0.193 $ 0.193
</TABLE>
---------
(1) As indicated in Note 3, quarterly results have been restated from amounts
previously reported due to the unauthorized trading losses.
(2) Represents cash distributions declared per common unit for the period
indicated. Distributions are paid in the quarter following declaration.
NOTE 17 -- 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 at various
points along the distribution chain and the leasing of certain terminalling and
storage assets. Prior to the July 1998 acquisition of the All American Pipeline
and SJV Gathering System, our predecessor had only marketing, gathering,
terminalling and storage operations. We evaluate segment performance based on
gross margin, gross profit and income before provision in lieu of income taxes
and extraordinary items.
F-24
<PAGE>
The following table summarizes segment revenues, gross margin, gross profit
and income (loss) before provision in lieu of income taxes and extraordinary
items:
<TABLE>
<CAPTION>
MARKETING,
GATHERING,
TERMINATING
(IN THOUSANDS) PIPELINE & STORAGE TOTAL
---------------------------------------------------------------------------------------------------
(RESTATED) (RESTATED)
<S> <C> <C> <C>
1999
Revenues:
External Customers $ 854,377 $ 3,885,515 $ 4,739,892
Intersegment(a) 131,445 - 131,445
Other 195 763 958
--------- ----------- -----------
Total revenues of reportable segments $ 986,017 $ 3,886,278 $ 4,872,295
========= =========== ===========
Segment gross margin(b) $ 58,001 $ (114,127) $ (56,126)
Segment gross profit(c) 55,384 (134,721) (79,337)
Net income (loss) before extraordinary item 46,075 (147,890) (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
---------------------------------------------------------------------------------------------------
COMBINED TOTAL FOR THE YEAR ENDED DECEMBER 31, 1998 (RESTATED) (UNAUDITED)
Revenues:
External Customers $ 254,228 $ 938,097 $ 1,192,325
Intersegment(a) 23,195 2,820 26,015
Other 603 (19) 584
--------- ----------- -----------
Total revenues of reportable segments $ 278,026 $ 940,898 $ 1,218,924
========= =========== ===========
Segment gross margin(b) $ 16,768 $ 14,612 $ 31,380
Segment gross profit(c) 15,723 10,360 26,083
Net income before provision in lieu of income taxes 3,187 5,478 8,665
Interest expense 9,108 3,523 12,631
Depreciation and amortization 4,031 1,340 5,371
Provision in lieu of income taxes 822 1,809 2,631
Capital expenditures 393,731 7,212 400,943
Total assets 471,864 135,322 607,186
---------------------------------------------------------------------------------------------------
NOVEMBER 23, 1998 TO DECEMBER 31, 1998 (RESTATED)
Revenues:
External Customers $ 54,089 $ 126,502 $ 180,591
Intersegment(a) 2,029 429 2,458
Other - 12 12
--------- ----------- -----------
Total revenues of reportable segments $ 56,118 $ 126,943 $ 183,061
========= =========== ===========
Segment gross margin(b) $ 3,546 $ 1,553 $ 5,099
Segment gross profit(c) 3,329 999 4,328
Net income 1,035 742 1,777
Interest expense 1,321 50 1,371
Depreciation and amortization 973 219 1,192
Capital expenditures 352 2,535 2,887
Total assets 471,864 135,322 607,186
---------------------------------------------------------------------------------------------------
JANUARY 1, 1998 TO NOVEMBER 22, 1998 (PREDECESSOR) (RESTATED)
Revenues:
External Customers $ 200,139 $ 811,595 $ 1,011,734
Intersegment(a) 21,166 2,391 23,557
Other 603 (31) 572
--------- ----------- -----------
Total revenues of reportable segments $ 221,908 $ 813,955 $ 1,035,863
========= =========== ===========
Segment gross margin(b) $ 13,222 $ 13,059 $ 26,281
Segment gross profit(c) 12,394 9,361 21,755
Net income before provision in lieu of income taxes 2,152 4,736 6,888
Interest expense 7,787 3,473 11,260
Depreciation and amortization 3,058 1,121 4,179
Provision in lieu of income taxes 822 1,809 2,631
Capital expenditures 393,379 4,677 398,056
---------------------------------------------------------------------------------------------------
</TABLE>
a) Intersegment sales were conducted on an arm's length basis.
b) Gross margin is calculated as revenues less cost of sales and operations
expenses.
c) Gross profit is calculated as revenues less costs of sales and operations
expenses and general and administrative expenses.
F-25
