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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to _____________
Commission file number: 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 Number)
500 Dallas
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 654-1414
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each exchange on which registered:
Common Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to the 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
$223,207,250 on March 22, 1999 based on $17.125 per unit, the closing price of
the Common Units as reported on the New York Stock Exchange on such date).
At March 22, 1999, there were outstanding 20,059,239 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
1998 FORM 10-K ANNUAL REPORT
Table of Contents
Page
Part I
Items 1. and 2. Business and Properties 3
Item 3. Legal Proceedings 20
Item 4. Submission of Matters to a Vote of Security Holders 20
Part II
Item 5. Market for Registrant's Common Units and Related Unitholder Matters 20
Item 6. Selected Financial Data 21
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 23
Item 7a. Quantitative and Qualitative - Disclosures About Market Risks 30
Item 8. Financial Statements and Supplementary Data 31
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 31
Part III
Item 10. Directors and Executive Officers of the General Partner 32
Item 11. Executive Compensation 33
Item 12. Security Ownership of Certain Beneficial Owners and Management 36
Item 13. Certain Relationships and Related Transactions 36
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 37
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements and
information that are based on the beliefs of Plains All American Pipeline, L.P.
and its general partner, as well as assumptions made by, and information
currently available to, the partnership and the general partner. 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 the partnership's
business strategy, plans and objectives of management of the partnership for
future operations. Such statements reflect the current views of the partnership
and the general partner with respect to future events, based on what they
believe are reasonable assumptions. These statements, however, are subject to
certain risks, uncertainties and assumptions, including, but not limited to (i)
the availability of adequate supplies of and demand for crude oil in the areas
in which the partnership operates, (ii) the impact of crude oil price
fluctuations, (iii) the effects of competition, (iv) the success of the
partnership=s risk management activities, (v) the availability (or lack thereof)
of acquisition or combination opportunities, (vi) the impact of current and
future laws and governmental regulations, (vii) environmental liabilities that
are not covered by an indemnity or insurance, (viii) general economic, market or
business conditions and (ix) uncertainties inherent in the Year 2000 Issue. If
one or more of these risks or uncertainties materialize, or if underlying
assumptions prove incorrect, actual results may vary materially from those in
the forward-looking statements. Except as required by applicable securities
laws, the partnership does not intend to update these forward-looking statements
and information.
2
PART I
Items 1. and 2. BUSINESS AND PROPERTIES
General
Plains All American Pipeline, L.P. ("PAA") and its operating partnerships,
Plains Marketing, L.P. ("Marketing") and All American Pipeline, L.P. ("AAPL")
(PAA, Marketing and AAPL collectively the "Partnership") were formed in late
1998 to acquire and operate the midstream crude oil business and assets of
certain wholly owned subsidiaries ("Plains Midstream Subsidiaries" or
"Predecessor") of Plains Resources Inc. ("Plains Resources"). All 1998 operating
data included herein includes the results of the Partnership and the
Predecessor. Plains All American Inc. (the "General Partner"), a wholly owned
subsidiary of Plains Resources, is the general partner of the Partnership and
the Partnership. The Partnership is engaged in interstate and intrastate crude
oil pipeline transportation and crude oil terminalling and storage activities
and gathering and marketing activities. The Partnership's operations are
concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
The Partnership owns and operates the All American Pipeline, a 1,233-mile
seasonally heated, 30-inch, common carrier crude oil pipeline extending from
California to West Texas, and the SJV Gathering System, a 45-mile, 16-inch,
crude oil gathering system in the San Joaquin Valley of California, both of
which the General Partner purchased from Wingfoot Ventures Seven, Inc.
("Wingfoot"), a wholly owned subsidiary of The Goodyear Tire & Rubber Company
("Goodyear"), in July 1998 for approximately $400 million (the "Acquisition").
The All American Pipeline is one of the newest interstate crude oil pipelines in
the United States, having been constructed by Goodyear between 1985 and 1987 at
a cost of approximately $1.6 billion, and is the largest capacity crude oil
pipeline connecting California and Texas, with a design capacity of 300,000
barrels per day of heavy crude oil. In West Texas, the All American Pipeline
interconnects with other crude oil pipelines that serve the Gulf Coast and
Cushing, Oklahoma, the largest crude oil trading hub in the United States (the
"Cushing Interchange") and the designated delivery point for New York Mercantile
Exchange ("NYMEX") crude oil futures contracts.
Production currently transported on the All American Pipeline originates
from the Santa Ynez field operated by Exxon and the Point Arguello field
operated by Chevron, both offshore California, and from the San Joaquin Valley.
Exxon and Chevron, as well as Texaco and Sun Operating L.P., which are other
working interest owners, are contractually obligated to ship all of their
production from these offshore fields on the All American Pipeline through
August 2007. The SJV Gathering System is used primarily to transport crude oil
from fields in the San Joaquin Valley to the All American Pipeline and to
intrastate pipelines owned by third parties. The capacity of the SJV Gathering
System is approximately 140,000 barrels per day. In addition to transporting
third-party volumes for a tariff, the Partnership is engaged in 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.
At the Cushing Interchange, the Partnership owns and operates a two million
barrel, above-ground crude oil terminalling and storage facility that has an
estimated daily throughput capacity of approximately 800,000 barrels per day
(the "Cushing Terminal"). The Cushing Terminal was completed in 1993, making it
the most modern facility in the area, and includes state-of-the-art design
features. The Partnership has initiated an expansion project that will add one
million barrels of storage capacity at an aggregate cost of approximately $10
million. The expansion project is expected to be completed in the second quarter
of 1999. Upon completion of the expansion project, management believes the
Cushing Terminal will be the third largest facility at the Cushing Interchange
(and the largest not owned by a major oil company) with an estimated 12% of that
area's storage capacity. The Partnership also owns 586,000 barrels of tank
capacity along the SJV Gathering System, 955,000 barrels of tank capacity along
the All American Pipeline and 360,000 barrels of tank capacity at Ingleside,
Texas on the Gulf Coast (the "Ingleside Terminal").
The Partnership's terminalling and storage operations generate revenue from
the Cushing Terminal through a combination of storage and throughput fees from
(i) refiners and gatherers seeking to segregate or custom blend crude oil for
refining feedstocks, (ii) pipelines, refiners and traders requiring segregated
tankage for foreign crude oil, (iii) traders who make or take delivery under
NYMEX contracts and (iv) producers seeking to increase their marketing
alternatives. The Cushing Terminal and the Partnership's other storage
facilities also facilitate the Partnership's merchant activities by enabling the
Partnership to buy and store crude oil when the price of crude oil in a given
month is less than the price of crude oil in a subsequent month (a "contango"
market) and to simultaneously sell crude oil futures contracts for delivery of
the crude oil in such subsequent month at the higher futures price, thereby
locking in a profit.
The Partnership's 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. The crude oil distribution chain extends
from the wellhead where crude oil moves by truck and gathering systems to
terminal and pipeline injection stations and major pipelines and
3
is transported to major crude oil trading locations for ultimate consumption
by refineries. In many cases, the Partnership matches supply and demand needs by
performing a merchant function--generating gathering and marketing margins by
buying crude oil at competitive prices, efficiently transporting or exchanging
the crude oil along the distribution chain and marketing the crude oil to
refineries or other customers. When there is a higher demand than supply of
crude oil in the near term, the price of crude oil in a given month exceeds the
price of crude oil in a subsequent month (a "backward" market). A backward
market has a positive impact on marketing margins because crude oil gatherers
can capture a premium for prompt deliveries. As premiums are paid for prompt
deliveries, storage opportunities are generally not profitable.
For the year ended December 31, 1998, the Partnership's pro forma gross
margin, earnings before interest expense, income taxes, depreciation and
amortization ("EBITDA") and net income totaled $74.1 million, $68.2 million and
$43.9 million, respectively. On a pro forma basis, the All American Pipeline and
the SJV Gathering System accounted for approximately 69% of the Partnership's
gross margin for the year ended December 31, 1998, while the terminalling and
storage activities and gathering and marketing activities accounted for
approximately 31%. See Item 6, "Selected Financial and Operating Data".
Initial Public Offering and Concurrent Transactions
On November 23, 1998, the Partnership completed an initial public offering
(the "IPO") of 13,085,000 common units representing limited partner interests
(the "Common Units") and received therefrom net proceeds of approximately $244.7
million. Concurrently with the closing of the IPO, certain transactions
described in the following paragraphs were consummated in connection with the
formation of the Partnership and the Partnership. Such transactions and the
transactions which occurred in conjunction with the IPO are referred to in this
report as the "Transactions."
Certain of the Plains Midstream Subsidiaries were merged into Plains
Resources, which sold the assets of these subsidiaries to the Partnership in
exchange for $64.1 million and the assumption of $11.0 million of related
indebtedness. At the same time, the General Partner conveyed all of its interest
in the All American Pipeline and the SJV Gathering System to the Partnership in
exchange for (i) 6,974,239 Common Units, 10,029,619 Subordinated Units and an
aggregate 2% general partner interest in the Partnership, (ii) the right to
receive Incentive Distributions as defined in the Partnership Agreement; and
(iii) the assumption by the Partnership of $175 million of indebtedness incurred
by the General Partner in connection with the acquisition of the All American
Pipeline and the SJV Gathering System.
In addition to the $64.1 million paid to Plains Resources, the Partnership
distributed approximately $177.6 million to the General Partner and used
approximately $3 million of the remaining proceeds to pay expenses incurred in
connection with the Transactions. The General Partner used $121.0 million of the
cash distributed to it to retire the remaining indebtedness incurred in
connection with the acquisition of the All American Pipeline and the SJV
Gathering System and to pay certain other costs associated with the Transactions
for the Partnership. The balance, $56.6 million, was distributed to Plains
Resources, which used the cash to repay indebtedness and for other general
corporate purposes.
In addition, concurrently with the closing of the IPO, the Partnership
entered into a $225 million bank credit agreement (the "Bank Credit Agreement")
that includes a $175 million term loan facility (the "Term Loan Facility") and a
$50 million revolving credit facility (the "Revolving Credit Facility"). The
Partnership may borrow up to $50 million under the Revolving Credit Facility for
acquisitions, capital improvements, working capital and general business
purposes. At closing, the Partnership had $175 million outstanding under the
Term Loan Facility, representing indebtedness assumed from the General Partner.
The following chart depicts the organization and ownership of PAA,
Marketing and AAPL after giving effect to the consummation of the Transactions,
including the sale of the Common Units sold in the IPO. The percentages
reflected in the organization chart represent the approximate ownership interest
in each of PAA, Marketing and AAPL individually and not on an aggregate basis.
The effective aggregate ownership percentages at the top of the chart reflect
the ownership interest of the Unitholders in the Partnership, Marketing and AAPL
on a combined basis. The 2% ownership of the General Partner reflects the
approximate effective ownership interest of the General Partner in the
Partnership, Marketing and AAPL on a combined basis.
4
[CHART APPEARS HERE]
5
Market Overview
The Department of Energy segregates the United States into five Petroleum
Administration Defense Districts ("PADDs") to gather information relating to
crude oil supply to key refining areas in the event of a national emergency. The
oil industry utilizes these districts in reporting statistics regarding crude
oil supply and demand. The All American Pipeline serves, directly or through
connecting lines, PADD V, which consists of seven western states, including
Alaska and Hawaii, PADD II, which consists of 15 states in the Midwest, and PADD
III, which consists of six states located in the South, principally bordering
the Gulf of Mexico. The table below sets forth supply, demand and shortfall
information for each PADD for 1998 and is derived from information published by
the Energy Information Administration.
Refinery Regional Supply
Petroleum Administration Defense District Demand Supply Shortfall
- ----------------------------------------- -------- -------- ---------
(thousands of barrels per day)
PADD I (East Coast) 1,600 -- 1,600
PADD II (Midwest) 3,300 500 2,800
PADD III (South) 6,900 3,300 3,600
PADD IV (Rockies) 500 300 200
PADD V (West Coast) 2,500 2,100 400
-------- -------- ---------
Total 14,800 6,200 8,600
======== ======== =========
As reflected in the table above, only 15% of the total refinery demand for
crude oil in PADD II can be supplied with crude oil produced in PADD II, with
the remainder (approximately 2.8 million barrels per day) provided by intra-U.S.
transfers of domestic crude oil production and imports from Canada and foreign
sources. In the 15-year period ending December 31, 1998, production from PADD II
has fallen approximately 52%, declining from approximately 1.1 million barrels
per day in 1984 to approximately 523,000 barrels per day in 1998. Over this same
time period, refinery demand for crude oil in this area has risen approximately
18%, increasing from approximately 2.8 million barrels per day in 1984 to
approximately 3.3 million barrels per day in 1998. Accordingly, over the last 15
years PADD II's reliance on sources outside the region has increased by
approximately 1.1 million barrels per day. Historically, PADD II refiners have
relied on crude oil production from PADD V to meet a portion of their refinery
input requirements.
Within PADD V, the supply/demand trend is quite different. Despite
significant population growth, PADD V refinery inputs (crude oil demand) have
decreased from a high of approximately 2.6 million barrels per day in 1989 to an
average of approximately 2.5 million barrels per day over the last five years.
This net decrease in refinery inputs is primarily due to (i) a reduction in the
number of operating refineries and (ii) an increase in the conversion capacity
of California refineries (which represent approximately 70% of the total PADD V
refinery inputs). Between 1985 and 1998, the number of operating California
refineries has declined from 34 (at approximately 79% of total capacity) to 21
(at approximately 95% of total capacity). A portion of the capacity lost due to
refinery closures has been met by higher capacity utilization at the continuing
refineries. Meanwhile, these units have been upgrading facilities to produce
legislatively-mandated cleaner-burning gasolines. As California refineries have
become more efficient, producing greater volumes of higher value products such
as gasoline from a lesser quantity of crude oil, overall refinery demand for
crude oil in PADD V has decreased. Excluding Hawaii, which imports approximately
80,000 barrels per day of foreign crude oil, and taking into account
geographically captive Canadian volumes which are transported to the Washington
state area, PADD V supply currently exceeds demand. In 1997 and 1998, a number
of large producers in California and Alaska announced multi-year capital
programs designed to increase production in California and Alaska. Subsequently,
several of these producers announced reductions in their 1999 capital spending
programs in response to the record low oil prices experienced in late-1998 and
early 1999, dampening the outlook for near term production growth. As a result,
the Partnership is unable to determine the long-term effects the low oil price
environment will have on California and Alaskan production volumes. However,
because of its low cost structure and the demand for crude oil in PADD II, the
Partnership believes the All American Pipeline will continue to be used to
transport California crude oil to connections with pipelines in Texas that will
deliver such crude oil to the Cushing Interchange in PADD II as well as the Gulf
Coast areas in PADD III.
Pending Acquisition
On March 17, 1999, the Partnership signed a definitive agreement with
Marathon Ashland Petroleum LLC to acquire Scurlock Permian LLC and certain other
pipeline assets. The cash purchase price for the acquisition is approximately
$138 million, plus associated closing and financing costs. The purchase price is
subject to adjustment at closing for working capital on April 1, 1999, the
effective date of the acquisition. Closing of the transaction is subject to
regulatory review and approval, consents from third parties, and customary due
diligence. Subject to satisfaction of the foregoing conditions, the transaction
is expected to close in the second quarter of 1999. The Partnership has received
a financing commitment from one of its existing lenders, which in addition to
other
6
financial resources currently available to the Partnership, will provide the
funds necessary to complete the transaction. The definitive agreement provides
that if either party fails to perform its obligations thereunder through no
fault of the other party, such defaulting party shall pay the nondefaulting
party $7.5 million as liquidated damages.
Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland
Petroleum LLC, is engaged in crude oil transportation, trading and marketing,
operating in 14 states with more than 2,400 miles of active pipelines, numerous
storage terminals and a fleet of more than 225 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, Howard, Martin, Midland, Regan,
Upton and Irion Counties, Texas. The assets to be acquired also include
approximately one million barrels of crude oil used for working inventory.
Crude Oil Pipeline Operations
All American Pipeline
The All American Pipeline is a common carrier crude oil pipeline system
that transports crude oil produced from fields offshore and onshore California
to locations in California and West Texas pursuant to tariff rates regulated by
the Federal Energy Regulatory Commission ("FERC"). 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 the Partnership.
The All American Pipeline is comprised of a heated pipeline system which
extends approximately 10 miles from Exxon's onshore facilities at Las Flores on
the California coast to Chevron's onshore facilities at Gaviota, California (24-
inch diameter pipe) and continues from Gaviota approximately 1,223 miles through
Arizona and New Mexico to West Texas (30-inch diameter pipe) where it
interconnects with other pipelines. These interconnecting common carrier
pipelines transport crude oil to the refineries located along the Gulf Coast and
to the Cushing Interchange. At the Cushing Interchange, these pipelines connect
with other pipelines that deliver crude oil to Midwest refiners. The All
American Pipeline also includes various pumping and heating stations, as well as
approximately one million barrels of crude oil storage tank capacity, to
facilitate the transportation of crude oil. The tank capacity is located at
stations in Sisquoc, Pentland and Cadiz, California, and at the station in Wink,
Texas. The Partnership owns approximately 5.0 million barrels of crude oil that
is used to maintain the All American Pipeline's linefill requirements.
The All American Pipeline has a designed throughput capacity of 300,000
barrels per day of heavy crude oil and larger volumes of lighter crude oils. As
currently configured, the pipeline's daily throughput capacity is approximately
216,000 barrels of heavy oil. In order to achieve designed capacity, certain
nominal capital expenditures would be required. The All American Pipeline is
operated from a control room in Bakersfield, California with a supervisory
control and data acquisition ("SCADA") computer system designed to continuously
monitor quantities of crude oil injected in and delivered through the All
American Pipeline as well as pressure and temperature variations. This
technology also allows for the batching of several different types of crude oil
with varying gravities. The SCADA system is designed to enhance leak detection
capabilities and provides for remote-controlled shut-down at every pump station
on the All American Pipeline. Pumping stations are linked by telephone and
microwave communication systems for remote-control operation of the All American
Pipeline which allows most of the pump stations to operate without full time
site personnel.
The Partnership performs scheduled maintenance on the pipeline and makes
repairs and replacements when necessary or appropriate. As one of the most
recently constructed major crude oil pipeline systems in the United States, the
All American Pipeline requires a relatively low level of maintenance capital
expenditures. The Partnership attempts to control corrosion of the pipeline
through the use of corrosion inhibiting chemicals injected into the crude
stream, external pipe coatings and an anode bed based cathodic protection
system. The Partnership monitors the structural integrity of the All American
Pipeline through a program of periodic internal inspections using electronic
"smart pig" instruments. The Partnership conducts a weekly aerial surveillance
of the entire pipeline and right-of-way to monitor activities or encroachments
on rights-of-way. Maintenance facilities containing equipment for pipe repair,
digging and light equipment maintenance are strategically located along the
pipeline. The Partnership believes that the All American Pipeline has been
constructed and is 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 standards of practice.
System Supply
The All American Pipeline transports several different types of crude oil,
including (i) Outer Continental Shelf ("OCS") crude oil received at the onshore
facilities of the Santa Ynez field at Las Flores, California and the onshore
facilities of the Point Arguello field located at Gaviota, California, (ii) Elk
Hills crude oil, received at Pentland, California from a connection with the SJV
7
Gathering System and (iii) various crude oil blends received at Pentland from
the SJV Gathering System, including West Coast Heavy and Mojave Blend.
OCS Supply. Exxon, which owns all of the Santa Ynez production, and
Chevron, Texaco and Sun Operating L.P., which own approximately one-half of the
Point Arguello production, have entered into transportation agreements
committing to transport all of their production from these fields on the All
American Pipeline. These agreements, which expire in August 2007, provide for a
minimum tariff with annual escalations. At December 31, 1998, the tariffs
averaged $1.41 per barrel for deliveries to connecting pipelines in California
and $2.96 per barrel for deliveries to connecting pipelines in West Texas. 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 the
Partnership have no other means of transporting their production and, therefore,
ship their volumes on the All American Pipeline at the posted tariffs. During
1998, approximately $33.6 million, or 45%, of the Partnership's pro forma gross
margin was attributable to volumes received from the Santa Ynez field and
approximately $12.9 million, or 17%, was attributable to volumes received from
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. The table below sets forth the historical volumes received from
both of these fields.
Year Ended December 31,
---------------------------------------------------------------
1998 1997 1996 1995 1994 1993 1992 1991
------ ------ ------ ------ ------ ------ ------ -------
(barrels in thousands)
Average daily volumes received from:
Point Arguello (at Gaviota) 26 30 41 60 73 63 47 29
Santa Ynez (at Las Flores) 68 85 95 92 34 -- -- --
------ ------ ------ ------ ------ ------ ------ -------
Total 94 115 136 152 107 63 47 29
====== ====== ====== ====== ====== ====== ====== =======
Absent operational or economic disruptions, the Partnership anticipates
that production from Point Arguello will continue to decline at percentage rates
which approximate historical decline rates, but that average production received
from the Santa Ynez field for 1999 will generally approximate 60,000 to 65,000
barrels per day. In connection with a proposed transfer of its ownership in
Point Arguello to a private independent oil company, Chevron provided notice to
the other working interest owners of its resignation as operator of the Point
Arguello field. The Partnership is unable to determine at this time if the
proposed transfer will occur or the consequences any such transfer or the
absence of any such transfer will have on Point Arguello production and the
resulting pipeline transportation volumes.
According to information published by the Minerals Management Service
("MMS"), significant additional proved, undeveloped reserves have been
identified offshore California which have the potential to be delivered on the
All American Pipeline. Future volumes of crude oil deliveries on the All
American Pipeline will depend on a number of factors that are beyond the
Partnership's control, including (i) the economic feasibility of developing the
reserves, (ii) the economic feasibility of connecting such reserves to the All
American Pipeline and (iii) the ability of the owners of such reserves to obtain
the necessary governmental approvals to develop such reserves. The owners of
these reserves are currently participating in a study (California Offshore Oil
and Gas Energy Resources, "COOGER") with various private organizations and
regulatory agencies to determine the best sites to locate onshore facilities
that will be required to handle and process potential production from these
undeveloped fields as well as the best methods of controlling potential
environmental dangers associated with offshore drilling and production. These
owners have also agreed to suspend drilling on the undeveloped leases until the
COOGER study is completed. The COOGER study is anticipated to be completed by
June 30, 1999, at which time owners of these undeveloped reserves must submit
their development plans to the MMS. There can be no assurance that the owners
will develop such reserves, that the MMS will approve development plans or that
future regulations or litigation will not prevent or retard their ultimate
development and production. There also can be no assurance that, if such
reserves were developed, a competing pipeline might not be built to transport
the production. In addition, a June 12, 1998 Executive Order of the President of
the United States extends until the year 2012 a statutory moratorium on new
leasing of offshore California fields. Existing fields are authorized to
continue production, but federal, state and local agencies may restrict permits
and authorizations for their development, and may restrict new onshore
facilities designed to serve offshore production of crude oil. San Luis Obispo
and Santa Barbara counties have adopted zoning ordinances that prohibit
development, construction, installation or expansion of any onshore support
facility for offshore oil and gas activity in the area, unless approved by a
majority of the votes cast by the voters of either county in an authorized
election. Any such restrictions, should they be imposed, could adversely affect
the future delivery of crude oil to the All American Pipeline.
San Joaquin Valley Supply. In addition to OCS production, crude oil from
fields in the San Joaquin Valley is delivered into the All American Pipeline at
Pentland through connections with the SJV Gathering System and pipelines
operated by EOTT, L.P. and ARCO. The San Joaquin Valley is one of the most
prolific oil producing regions in the continental United States, producing
8
approximately 591,000 barrels per day of crude oil during the first nine months
of 1998 that accounted for approximately 65% of total California production and
11% of the total production in the lower 48 states. 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.
Year Ended December 31,
--------------------------------------------------------------------------------
1998(1) 1997 1996 1995 1994 1993 1992 1991 1990 1989
-------- ------ ------ ------ ------ ------ ------ ------ ------ ------
(barrels in thousands)
Average daily volumes:
San Joaquin Valley production 591 584 579 569 578 588 609 634 629 646
Total California production
(excluding OCS volumes) 780 781 772 764 784 803 835 875 879 907
- --------------
(1) Reflects information through September 1998.
Drilling and exploitation activities have increased in the San Joaquin
Valley over the last few years, primarily due to the change in ownership of
several large fields and technological advances in horizontal drilling and steam
assisted recovery methods that have improved the overall economics of field
development and reductions in the operating costs of these fields. The near term
outlook for any potential production increases has been adversely affected by
the depressed price of oil and related reductions in capital spending plans
announced by several California producers.
Alaskan North Slope Supply. Historically, the All American Pipeline had
also transported volumes of Alaskan North Slope crude oil. In 1996, the U.S.
government repealed the export ban on crude oil produced from the Alaskan North
Slope which had effectively prohibited the sale of Alaskan North Slope crude oil
to sources outside the U.S. Prior to its repeal, this ban had the impact of
increasing volumes of Alaskan crude oil delivered into the California market.
Shipments of Alaskan North Slope crude oil on the All American Pipeline ceased
in February 1997, shortly after the repeal of the export ban. In addition, ARCO
sold the only pipeline that could bring Alaskan North Slope crude oil to the All
American Pipeline. This pipeline will be converted to natural gas service
thereby eliminating the physical capability to ship Alaskan North Slope crude
oil on the All American Pipeline.
System Demand
Deliveries from the All American Pipeline are made to refineries within
California, along the Gulf Coast or in the Midwest through connecting pipelines
of other companies. Demand for crude oil shipped on the All American Pipeline in
each of these markets is affected by numerous factors, including refinery
utilization and crude oil slate requirements, regional crude oil production,
foreign imports, intra-U.S. transfers of crude oil and the price differential
(net of transportation cost) between the California and Midwest markets.
Deliveries are made to California refineries through connections with
third-party pipelines at Sisquoc, Pentland and Mojave. The deliveries at Sisquoc
and Pentland are OCS crude oil while the deliveries at Mojave are primarily
Mojave Blend. Crude oil transported to West Texas is primarily West Coast Heavy
and is delivered to third-party pipelines at Wink and McCamey, Texas. At Wink,
West Coast Heavy crude is blended with Domestic Sweet Crude to increase the
gravity (the blend is commonly referred to as West Coast Sour), permitting
delivery into third party pipelines that can transport the crude to the Cushing
Interchange. At McCamey, West Coast Heavy and OCS crude oil are delivered to a
third-party pipeline that supplies refiners on the Gulf Coast.
The following table sets forth All American Pipeline average deliveries per
day within and outside California for each of the years in the five-year period
ended December 31, 1998.
Year Ended December 31,
---------------------------------------
1998 1997 1996 1995 1994
------- ------ ------ ------ ------
(barrels in thousands)
Average daily volumes delivered to:
California
Sisquoc 24 21 17 11 21
Pentland 69 74 71 65 56
Mojave 22 32 6 -- --
------- ------ ------ ------ ------
Total California 115 127 94 76 77
Texas 59 68 113 141 108
------- ------ ------ ------ ------
Total 174 195 207 217 185
======= ====== ====== ====== ======
9
SJV Gathering System
The SJV Gathering System is a proprietary pipeline system that only
transports crude oil purchased by the Partnership. As a proprietary pipeline,
the SJV Gathering System is not subject to common carrier regulations and does
not transport crude oil for third parties. The primary purpose of the pipeline
is to gather crude oil from various sources in the San Joaquin Valley and to
blend such crude oil along the pipeline system in order to deliver either West
Coast Heavy or Mojave Blend into the All American Pipeline. Certain crude
streams are segregated and delivered into either the All American Pipeline or to
third party pipelines connected to the SJV Gathering System.
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. The SJV Gathering System also includes approximately
586,000 barrels of tank capacity, which has historically been used to facilitate
movements along the pipeline system.
The SJV Gathering System is operated in conjunction with, and with the same
SCADA system used in the operations of, the All American Pipeline. The
Partnership also takes measures to protect the pipeline from corrosion and
routinely inspects the pipeline using the same procedures and practices employed
in the operation of the All American Pipeline. Like the All American Pipeline,
the SJV Gathering System was constructed and is maintained in all material
respects in accordance with applicable federal, state and local laws and
regulations, standards recommended by the American Petroleum Institute and
accepted industry standards of practice.
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 and Elk Hills fields. The table below sets forth the
historical volumes received into the SJV Gathering System.
Year Ended December 31,
---------------------------------------
1998 1997 1996 1995 1994
------- ------ ------ ------ ------
(barrels in thousands)
Total average daily volumes 85 91 67 50 54
To increase utilization and margins relating to the SJV Gathering System,
the Partnership has initiated a wellhead gathering, transportation and marketing
program in the San Joaquin Valley. The new program is similar to a program to
purchase crude oil from independent producers successfully implemented by the
Plains Midstream Subsidiaries in Texas, Oklahoma, Kansas and Louisiana under
which volumes increased from 1,300 barrels per day in 1990 to 88,000 barrels per
day in 1998. The Partnership has committed resources to its new gathering
program by hiring an additional lease buyer, activating an existing truck
unloading station and arranging to make additional connections with other
pipeline systems in the San Joaquin Valley, including access into the Pacific
Pipeline. In addition, the Partnership has entered into an arrangement with
various parties whereby the Partnership has reserved up to 40,000 barrels per
day of capacity for movements into the Pacific Pipeline, and all crude oil
sourced by one such party from the Midway Sunset field will be delivered by the
Partnership into the Pacific Pipeline via the SJV Gathering System. Construction
of the Pacific Pipeline, a pipeline system that will serve the LA Basin, was
completed in early 1999. See "Competition."
Terminalling and Storage Activities and Gathering and Marketing Activities
Terminalling and Storage
The Cushing Terminal was constructed in 1993 to capitalize on the crude oil
supply and demand imbalance in the Midwest 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 the Partnership's merchant activities
relating to its lease gathering and bulk trading activities. The Ingleside
Terminal was constructed in 1979 and purchased by the Plains Midstream
Subsidiaries in 1996 to enhance its lease gathering activities in South Texas.
The Cushing Terminal has a total storage capacity of two million barrels,
comprised of fourteen 100,000 barrel tanks and four 150,000 barrel tanks 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 up to 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. A one million
10
barrel expansion project to add four 250,000 barrel tanks is currently underway
at the Cushing Terminal with completion targeted for the second quarter of 1999.
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, the Partnership incorporated
certain attributes into the design of the Cushing Terminal including (i)
multiple, smaller tanks to facilitate simultaneous handling of multiple crude
varieties in accordance with normal pipeline batch sizes, (ii) dual header
systems connecting each tank to the main manifold system to facilitate efficient
switching between crude grades with minimal contamination, (iii) bottom drawn
sump pumps that enable each tank to be efficiently drained down to minimal
remaining volumes to minimize crude contamination and maintain crude integrity,
(iv) a mixer on each tank to facilitate blending crude grades to refinery
specifications, and (v) 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, the Partnership believes it is favorably positioned to serve the needs
of Midwest refiners to handle increasing varieties of crude transported through
the Cushing Interchange.
The Cushing Terminal also incorporates numerous environmental and
operational safeguards. The Partnership believes that its terminal is the only
one at the Cushing Interchange for 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
above ground pipelines. Like the All American Pipeline and the SJV Gathering
System, the Cushing Terminal is operated by a SCADA system 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 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 line
that, in the event of a fire, is connected to the automated fire water
distribution system.
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 a NYMEX delivery point and a cash market hub, the Cushing
Interchange serves as the 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 Ingleside Terminal was constructed in 1979 and purchased by the Plains
Midstream Subsidiaries in 1996 to enhance its lease gathering activities in
South Texas. The Ingleside Terminal is located near the Gulf Coast port of
Corpus Christi, Texas. The Ingleside Terminal is comprised of 11 tanks ranging
in size from a minimum of 15,000 barrels to a maximum of 50,000 barrels. Three
of these tanks are heated, which allows for storage of heavier products. The
terminal has access to the receipt of crude oil and refined petroleum products
from trucks and barges. Likewise, the terminal can deliver crude oil and refined
petroleum products to barges and trucks. The Partnership leases a barge dock
approximately one mile from the Ingleside Terminal and is connected to the dock
by four pipelines ranging in size from 8 inches to 12 inches in diameter. The
dock lease can be extended in five-year intervals through 2021.
The Partnership's terminalling and storage operations generate revenue
through terminalling and storage fees paid by third parties as well as by
utilizing the tankage in conjunction with its merchant activities. Storage fees
are generated when the Partnership leases tank capacity to third parties.
Terminalling fees, also referred to as throughput fees, are generated when the
Partnership receives crude oil from one connecting pipeline (generally received
in batch sizes of 25,000 to 400,000 barrels) and redelivers 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 (which is generally
three to ten days). Both terminalling and storage fees are generally earned from
(i) refiners and gatherers that segregate or custom blend crudes for refining
feedstocks, (ii) pipeline operators, refiners or traders that need segregated
tankage for foreign cargoes, (iii) traders who make or take delivery under NYMEX
contracts and (iv) producers and resellers that seek to increase their marketing
alternatives. The tankage that is used to support the Partnership's arbitrage
activities position the Partnership to capture margins in a contango market or
when the market switches from contango to backwardation. The following table
sets forth the daily throughput volumes for the Partnership's terminalling and
storage operations, and quantity of tankage leased to third parties from 1994
through 1998.
11
Year Ended December 31,
---------------------------------------
1998 1997 1996 1995 1994
------- ------ ------ ------ ------
(barrels in thousands)
Throughput volumes (average
daily volumes):
Cushing Terminal 69 69 56 43 29
Ingelside Terminal 11 8 3 -- --
------- ------ ------ ------ ------
Total 80 77 59 43 29
======= ====== ====== ====== ======
Storeage leased to third parties
(monthly average volumes):
Cushing Terminal 890 414 203 208 464
Ingleside Terminal 260 254 211 -- --
------- ------ ------ ------ ------
Total 1,150 668 414 208 464
======= ====== ====== ====== ======
The Partnership has committed 1.5 million barrels of its capacity at the
Cushing Terminal to storage arrangements with third parties through mid-1999.
Gathering and Marketing Activities
The Partnership's gathering and marketing activities are primarily
conducted in Louisiana, Texas, Oklahoma and Kansas and include (i) purchasing
crude oil from producers at the wellhead and in bulk from aggregators at major
pipeline interconnects and trading locations, (ii) transporting such crude oil
on its own proprietary gathering assets or assets owned and operated by third
parties when necessary or cost effective, (iii) exchanging such 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 (iv) marketing crude oil to refiners or other resellers. For the year ended
December 31, 1998 the Partnership purchased approximately 88,000 barrels per day
of crude oil directly at the wellhead. The Partnership purchases crude oil from
producers under contracts that range in term from a thirty-day evergreen to two
years. Gathering and marketing activities are characterized by large volumes of
transactions with lower margins relative to pipeline and terminalling and
storage operations.
The following table shows the average daily volume of the Partnership's
lease gathering and bulk purchases from 1995 through 1998.
Year Ended December 31,
-----------------------------------
1998 1997 1996 1995
-------- ------- ------ ------
(barrels in thousands)
Lease gathering 88 71 59 46
Bulk purchases 95 49 32 10
-------- ------- ------ ------
Total volumes 183 120 91 56
======== ======= ====== ======
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 the Partnership's field personnel to
purchase and transport the crude oil to market. The Partnership utilizes
pipelines, trucks and barges owned and operated by third parties and the
Partnership's truck fleet and gathering pipelines to transport the crude oil to
market. The Partnership owns approximately 29 trucks, 30 tractor-trailers and 22
injection stations.
Pursuant to a Crude Oil Marketing Agreement with Plains Resources (the
"Crude Oil Marketing Agreement"), the Partnership is the exclusive
marketer/purchaser for all of Plains Resources' equity crude oil production. The
Crude Oil Marketing Agreement provides that the Partnership will purchase for
resale at market prices all of Plains Resources' crude oil production for which
it will charge a fee of $0.20 per barrel. This fee will be adjusted every three
years based upon then existing market conditions. The Crude Oil Marketing
Agreement will terminate upon a "change of control" of Plains Resources or the
General Partner. On a pro forma basis, revenues generated under the Crude Oil
Marketing Agreement for the year ended December 31, 1998 would have been
approximately $1.5 million. For the year ended December 31, 1998, Plains
Resources produced approximately 20,800 barrels per day which would be subject
to the Crude Oil Marketing Agreement. Plains Resources owns an approximate 100%
working interest in each of its fields.
Bulk Purchases. In addition to purchasing crude oil at the wellhead from
producers, the Partnership purchases 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. The Partnership purchases crude oil in bulk when it
believes 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 the Partnership's bulk
12
purchases fluctuate from period to period. The Partnership's 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. The Partnership sells its
crude oil to major integrated oil companies and independent refiners in various
types of sale and exchange transactions, generally at market-responsive prices
for terms ranging from one month to three years.
As the Partnership purchases crude oil, it establishes 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, the Partnership seeks to maintain a position that is substantially
balanced between crude oil purchases and sales and future delivery obligations.
The Partnership from time to time enters into fixed price delivery contracts,
floating price collar arrangements, financial swaps and oil futures contracts as
hedging devices. To ensure a fixed price for future production, the Partnership
may sell a futures contract and thereafter either (i) make physical delivery of
its crude oil to comply with such contract or (ii) buy a matching futures
contract to unwind its futures position and sell its crude oil to a customer.
The Partnership's policy is generally to purchase only crude oil for which it
has a market and to structure its sales contracts so that crude oil price
fluctuations do not materially affect the gross margin which it receives. The
Partnership does 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 the Partnership to indeterminable 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. The Partnership's management monitors
crude oil volumes, grades, locations and delivery schedules and coordinates
marketing and exchange opportunities, as well as NYMEX hedging positions. This
coordination ensures that the Partnership's NYMEX hedging activities are
successfully implemented.
Crude Oil Exchanges. The Partnership pursues exchange opportunities to
enhance margins throughout the gathering and marketing process. When
opportunities arise to increase its margin or to acquire a grade of crude oil
that more nearly matches its delivery requirement or the preferences of its
refinery customers, the Partnership exchanges physical crude oil with third
parties. These exchanges are effected through contracts called exchange or buy-
sell agreements. Through an exchange agreement, the Partnership agrees to buy
crude oil that differs in terms of geographic location, grade of crude oil or
delivery schedule from crude oil it has available for sale. Generally, the
Partnership enters into exchanges to acquire crude oil at locations that are
closer to its end markets, thereby reducing transportation costs and increasing
its margin. The Partnership also exchanges its 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 enters 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 its delivery contracts.
Producer Services. Crude oil purchasers who buy from producers compete on
the basis of competitive prices and highly responsive services. The Partnership
believes that its ability to offer high-quality field and administrative
services to producers is a key factor in maintaining volumes of purchased crude
oil and obtaining 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 the Partnership), 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, the Partnership 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. The Partnership's merchant activities involve the purchase of crude
oil for resale and require significant extensions of credit by the Partnership's
suppliers of crude oil. In order to assure the Partnership's ability to perform
its obligations under crude purchase agreements, various credit arrangements are
negotiated with the Partnership's crude oil suppliers. Such arrangements include
open lines of credit directly with the Partnership and standby letters of credit
issued under the Letter of Credit Facility. See Item 7, "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Capital
Resources, Liquidity and Financial Condition."
13
When the Partnership markets crude oil, it must determine the amount, if
any, of the line of credit to be extended to any given customer. If the
Partnership determines that a customer should receive a credit line, it must
then decide on the amount of credit that should be extended. Since typical
Partnership 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 the Partnership's business. The Partnership believes its sales
are made to creditworthy entities or entities with adequate credit support.
Credit review and analysis are also integral to the Partnership's 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, the Partnership must
determine whether the operator has sufficient financial resources to make such
payments and distributions and to indemnify and defend the Partnership 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.
Operating Activities
The following table presents certain information with respect to the
Predecessor's and the Partnership's pipeline activities and its terminalling and
storage and gathering and marketing activities during the year ended December
31, 1998.
November 23, January 1,
1998 1998
Through Through Combined
December 31, November 22, Total
1998 1998 1998
------------- ------------- --------
(Predecessor)
(in thousands)
Sales to unaffiliated customers:
Pipeline $ 56,118 $221,305 $277,423
Terminalling and storage and
gathering and marketing 122,785 755,496 878,281
Operating profits:
Pipeline(1) $ 3,546 $ 13,222 $ 16,768
Terminalling and storage and
gathering and marketing 3,953 17,759 21,712
Identifiable assets:
Pipeline N/A N/A $472,144
Terminalling and storage and
gathering and marketing N/A N/A 138,064
- ----------------
(1) Consists primarily of pipeline tariff and margin revenues less pipeline
margin purchases and operating costs.
(2) Consists primarily of crude oil sales and terminalling and storage revenues
less crude oil purchases and operating costs.
Customers
Sempra Energy Trading Corporation and Koch Oil Company accounted for 30%
and 17%, respectively, of the Partnership's 1998 revenues. No other individual
customer accounted for greater than 10% of the Partnership's revenue.
Competition
The All American Pipeline encounters competition from foreign oil imports
and other pipelines that serve the California market and the refining centers in
the Midwest and on the Gulf Coast.
Construction of the Pacific Pipeline, a competing crude oil pipeline system
connecting the San Joaquin Valley to refinery markets in the Los Angeles Basin
was completed in March 1999. A substantial portion of the shipments expected to
be transported on the Pacific Pipeline will be redirected from barge and train
service. However, the Partnership expects that certain volumes currently
transported on the All American Pipeline may be redirected to Los Angeles on
such pipeline.
Competition among common carrier pipelines is based primarily on
transportation charges, access to producing areas and demand for the crude oil
by end users. The Partnership believes that high capital requirements,
environmental considerations and the difficulty in acquiring rights of way and
related permits make it unlikely that a competing pipeline system comparable in
size and scope to the All American Pipeline will be built in the foreseeable
future.
14
The Partnership faces intense competition in its terminalling and storage
activities and gathering and marketing activities. Its 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 the Partnership's and control
substantially greater supplies of crude oil.
Regulation
The Partnership's 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 the Partnership's cost of doing business and, consequently, affects
its profitability. However, the Partnership does not believe that it is affected
in a significantly different manner by these regulations than its competitors.
Due to the myriad and complex federal and state statutes and regulations which
may affect the Partnership, directly or indirectly, the following discussion of
certain statutes and regulations should not be relied upon as an exhaustive
review of all regulatory considerations affecting the Partnership's operations.
Pipeline Regulation
The Partnership's pipelines are subject to regulation by the Department of
Transportation ("DOT") 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 the Partnership 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 (the "Pipeline Safety Act") amends the
HLPSA in several important respects. It requires the Research and Special
Programs Administration ("RSPA") of DOT 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
DOT of pipeline operator qualification rules requiring minimum training
requirements for operators, and requires that pipeline operators provide maps
and records to RSPA. It also authorizes RSPA 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. The Partnership believes that its pipeline operations are in
substantial compliance with applicable HLPSA and Pipeline Safety Act
requirements. Nevertheless, significant expenses could be incurred 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. The
Partnership does not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which it operates.
Transportation and Sale of Crude Oil
In October 1992 Congress passed the Energy Policy Act of 1992 ("Energy
Policy Act"). 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: (i) 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; (ii) the complainant was contractually barred
from challenging the rate prior to enactment; or (iii) 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.
15
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
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 applicable procedures.
In a recent 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.
There is also pending at the FERC a proceeding 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 September 25, 1997, the
administrative law judge in the Santa Fe Proceeding issued an initial decision
addressing various aspects of the tax allowance issue as it affects publicly
traded partnerships, as well as various technical issues involving the
application of the FERC oil pipeline ratemaking methodology. The administrative
law judge's initial decision in the Santa Fe Proceeding is currently pending
review by the FERC. In such review, it is possible that the FERC could alter its
current rulings on the tax allowance issue or on the application of the FERC oil
pipeline ratemaking methodology.
The FERC generally has not investigated rates, such as those currently
charged by the Partnership, 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 the Partnership's gross margins on
transportation are produced by rates that are either grandfathered or set by
agreement of the parties. The rates for substantially all of the crude oil
transported from California to West Texas are grandfathered and not subject to
decreases through the application of indexing. 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, the Partnership believes that the rates
now in effect can be sustained, although no assurance can be given that the
rates currently charged by the Partnership would ultimately be upheld if
challenged. In addition, the Partnership does not believe that an adverse
determination on the tax allowance issue in the Santa Fe Proceeding would have a
detrimental impact upon the current rates charged by the Partnership.
Trucking Regulation
The Partnership operates a fleet of trucks to transport crude oil as a
private carrier. As a private carrier, the Partnership is subject to certain
motor carrier safety regulations issued by the DOT. 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. The Partnership is also subject to
OSHA with respect to its 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 the Partnership's operations and costs. In
particular, the Partnership's activities in connection with storage and
transportation of crude oil and other liquid hydrocarbons and its use of
facilities for treating, processing
16
or otherwise handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. As with the industry generally, compliance with
existing and anticipated regulations increases the Partnership's overall cost of
business. Such areas affected include capital costs to construct, maintain and
upgrade equipment and facilities. While these regulations affect the
Partnership's capital expenditures and earnings, the Partnership believes that
such regulations do not affect its competitive position in that the operations
of its competitors that comply with such regulations are similarly affected.
Environmental regulations have historically been subject to frequent change by
regulatory authorities, and the Partnership is unable to predict the ongoing
cost to it of complying with these laws and regulations or the future impact of
such regulations on its operation. Violation of federal or state environmental
laws, regulations and permits can result in the imposition of significant civil
and criminal penalties, injunctions and construction bans or delays. A discharge
of hydrocarbons or hazardous substances into the environment could, to the
extent such event is not insured, subject the Partnership 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, in certain environmentally sensitive
areas, along shorelines or in the exclusive economic zone of the U.S. In the
event of an oil spill into such waters, substantial liabilities could be imposed
upon the Partnership. States in which the Partnership operates have also enacted
similar laws. Regulations are currently being developed under OPA and state laws
that may also impose additional regulatory burdens on the Partnership.
The FWPCA imposes restrictions and strict controls regarding the discharge
of pollutants into navigable waters. Permits must be obtained to discharge
pollutants to state and federal waters. The FWPCA imposes substantial potential
liability for the costs of removal, remediation and damages. The Partnership
believes that compliance with existing permits and compliance with foreseeable
new permit requirements will not have a material adverse effect on the
Partnership's financial condition or results of operations.
Some states maintain groundwater protection programs that require permits
for discharges or operations that may impact groundwater conditions. The
Partnership believes that it is in substantial compliance with these state
requirements.
Air Emissions
The operations of the Partnership are subject to the Federal Clean Air Act
and comparable state and local statutes. The Partnership believes that its
operations are in substantial compliance with such statutes in all states in
which they 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 the Partnership's facilities. Although no
assurances can be given, the Partnership believes implementation of the 1990
Federal Clean Air Act Amendments will not have a material adverse effect on the
Partnership's financial condition or results of operations.
Solid Waste
The Partnership generates hazardous and 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 that are currently exempt from RCRA requirements. At present, the
Partnership is not required to comply with a substantial portion of the RCRA
requirements because the Partnership's operations generate minimal quantities of
hazardous wastes. However, it is possible that oil and 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 by the
Partnership.
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,
17
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 its ordinary operations, the Partnership may
generate waste that may fall within CERCLA's definition of a "hazardous
substance." The Partnership 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 or released into the environment.
The Partnership currently owns or leases, and has in the past owned or
leased, properties where hydrocarbons are being or have been handled. Although
the Partnership has 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 the Partnership or
on or under other locations where such 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
the Partnership's control. These properties and wastes disposed thereon may be
subject to CERCLA, RCRA and analogous state laws. Under such laws, the
Partnership 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
The Partnership is 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. The Partnership believes that its operations are in
substantial compliance with OSHA requirements, including general industry
standards, record keeping requirements, employee training regulations 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 facilities of the
Partnership are in areas that may be designated as habitat for endangered
species, the Partnership believes that it is in substantial compliance with the
ESA. However, the discovery of previously unidentified endangered species could
cause the Partnership 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. The Partnership believes
that its operations are in substantial compliance with such regulations.
Environmental Remediation
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. The
Partnership has submitted a closure plan to the Regional Water Quality Board
("RWQB"). At the request of the RWQB, groundwater monitoring wells have been
installed from which water samples will be analyzed semi-annually. No
hydrocarbon contamination was detected in initial analyses taken in January
1999. The RWQB approval of PAA's closure plan is not expected until subsequent
semi-annual analyses have been performed. If the Partnership's closure plan is
disapproved, a government mandated remediation of the spill could require
significant expenditures (currently estimated to be approximately $350,000),
provided however, no assurance can be given that the actual cost thereof will
not exceed such estimate. The Partnership does not believe the ultimate
resolution of this issue will have a material adverse affect on the
Partnership's consolidated financial position, results of operations or cash
flows.
Prior to being acquired by the Partnership's predecessors 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. The
Partnership has proposed a voluntary state-administered remediation of the
contamination on the property to determine whether the contamination extends
outside the property boundaries. If the Partnership's plan is disapproved, a
government mandated remediation of the spill could require more significant
expenditures, currently estimated to approximate $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 the Partnership from Plains
Resources. The Partnership does not believe the ultimate resolution of this
issue will have a material adverse affect on the Partnership's
18
consolidated financial position, results of operations or cash flows. See Item
13, "Certain Relationships and Related Transactions--Relationship with Plains
Resources--Indemnity from the General Partner."
The Partnership may experience future releases of crude oil into the
environment from its pipeline and storage operations, or discover releases that
were previously unidentified. While the Partnership maintains 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 the All American Pipeline, the SJV Gathering System,
the Cushing Terminal, the Ingleside Terminal or other Partnership assets may
substantially affect the Partnership's 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. The Partnership maintains
insurance of various types that it considers to be adequate to cover its
operations and properties. The insurance covers all of the Partnership's assets
in amounts considered reasonable. The insurance policies are subject to
deductibles that the Partnership considers reasonable and not excessive. The
Partnership's 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, the
Partnership's 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 the Partnership's operations and financial
condition. The Partnership believes that it is adequately insured for public
liability and property damage to others with respect to its operations. With
respect to all of its coverage, no assurance can be given that the Partnership
will be able to maintain adequate insurance in the future at rates it considers
reasonable.
Title to Properties
Substantially all of the Partnership's 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. Permits have been obtained 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. Permits
have also been obtained 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, the Partnership has
the right of eminent domain to acquire rights-of-way and lands necessary for the
operations of the All American Pipeline, a common carrier pipeline.
Some of the leases, easements, rights-of-way, permits and licenses
transferred to the Partnership, upon its formation in 1998, required the consent
of the grantor to transfer such rights, which in certain instances is a
governmental entity. The General Partner believes that it has obtained such
third-party consents, permits and authorizations as are sufficient for the
transfer to the Partnership of the assets necessary for the Partnership to
operate its business in all material respects as described in this report. With
respect to any consents, permits or authorizations which have not yet been
obtained, the 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 the Partnership's business.
The General Partner believes that the Partnership has satisfactory title to
all of its 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 the Plains Midstream
Subsidiaries or the Partnership, the General Partner believes that none of such
burdens will materially detract from the value of such properties or from the
Partnership's interest therein or will materially interfere with their use in
the operation of the Partnership's business.
19
Employees
To carry out the operations of the Partnership, the General Partner or its
affiliates employ approximately 210 employees. None of such employees of the
General Partner is represented by labor unions, and the General Partner
considers its employee relations to be good.
Item 3. LEGAL PROCEEDINGS
The Partnership, in the ordinary course of business, is a claimant and/or a
defendant in various legal proceedings in which its exposure, individually and
in the aggregate, is not considered material to the Partnership.
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.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS
The Common Units, representing limited partner interests in the
Partnership, are listed and traded on the New York Stock Exchange under the
symbol "PAA". The Common Units began trading on November 18, 1998, at an initial
public offering price of $20.00 per Common Unit. On March 22, 1999, the market
price for the Common Units was $17.125 per unit and there were approximately
12,300 record holders and beneficial owners (held in street name) of the
Partnership's Common Units.
The following table sets forth, for the portion of the fourth quarter 1998
in which the Common Units were traded, the range of high and low closing sales
prices for the Common Units as reported on the New York Stock Exchange Composite
Tape, and the amount of cash distribution paid per Common Unit for the portion
of the fourth quarter 1998 commencing November 23, 1998, the date of closing of
the IPO.
Common Unit Price Range
-----------------------
High Low Cash Distribution Paid Per Unit
------ ------ -------------------------------
1998:
4th Quarter $20.06 $16.75 $0.193 (paid February 12, 1999
for period from November
23, 1998, through
December 31, 1998)
The Partnership has also issued Subordinated Units, all of which are held
by an affiliate of the General Partner, for which there is no established public
trading market. The Partnership will distribute to its partners (including
holders of Subordinated Units), on a quarterly basis, all of its Available Cash
in the manner described herein. Available Cash generally means, with respect to
any quarter of the Partnership, all cash on hand at the end of such quarter less
the amount of cash reserves that is necessary or appropriate in the reasonable
discretion of the General Partner to (i) provide for the proper conduct of the
Partnership's business, (ii) comply with applicable law or any Partnership debt
instrument or other agreement, or (iii) provide funds for distributions to
Unitholders and the General Partner in respect of any one or more of the next
four quarters. Available Cash is defined in the Second Amended and Restated
Agreement of Limited Partnership of Plains All American Pipeline, L.P. (the
APartnership Agreement") listed as an exhibit to this report. The Partnership
Agreement defines Minimum Quarterly Distributions as $ 0.45 for each full fiscal
quarter (prorated for the initial partial fiscal quarter commencing November 23,
1998, the closing date of the IPO through year-end 1998). The Partnership made a
cash distribution in the amount of $ 5.8 million on February 12, 1999, in
respect to its Common Units and Subordinated Units for the period of November
23, 1998 through year-end 1998. This payment was based upon $ 0.193 per unit,
which was the Minimum Quarterly Distribution prorated for the partial quarter in
accordance with the Partnership Agreement. Distributions of Available Cash to
the holder 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.
20
Under the terms of the Partnership's Bank Credit Agreement and Letter of
Credit Facility, the Partnership is prohibited from declaring or paying any
distribution to Unitholders if a Default or Event of Default (as defined in such
agreements) exists thereunder. See Management's Discussion and Analysis of
Financial Condition and Results of Operations - Capital Resources, Liquidity and
Financial Condition in Item 7 of this report.
Item 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL AND OPERATING DATA
On November 23, 1998, the Partnership completed the IPO and the
Transactions whereby the Partnership became the successor to the business of the
Predecessor. The following selected pro forma and historical financial
information was derived from the audited consolidated financial statements of
the Partnership as of December 31, 1998, and for the period from November 23,
1998 through December 31, 1998, and the audited combined financial statements of
the Predecessor, as of December 31, 1997, 1996, 1995 and 1994 and for the period
from January 1, 1998 through November 22, 1998 and for the years ended December
31, 1997, 1996, 1995 and 1994, including the notes thereto, certain of which
appear elsewhere in this Report. The Predecessor operating data for all periods
is derived from the records of the Partnership and the Predecessor. Commencing
July 30, 1998, (the date of the 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. The selected financial data should be read in
conjunction with the consolidated and combined financial statements, including
the notes thereto, and Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations".
Year November 23, January 1,
Ended 1998 to 1998 to Year Ended December 31,
December 31, December 31, November 22, -------------------------------------------------------
1998(1) 1998 1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ ------------ ------------ ----------
(Pro forma) (Predecessor) (Predecessor)
(Unaudited) (in thousands, except unit data)
Income Statement Data
Revenues $1,568,853 $ 176,445 $ 953,244 $ 752,522 $ 531,698 $ 339,825 $ 199,239
Cost of Sales and
Operations 1,494,732 168,946 922,263 740,042 522,167 333,459 193,050
------------ ------------ ------------ ------------ ------------ ------------ ----------
Gross Margin 74,121 7,499 30,981 12,480 9,531 6,366 6,189
------------ ------------ ------------ ------------ ------------ ------------ ----------
General and administrative
expenses 6,501 771 4,526 3,529 2,974 2,415 2,376
Depreciation and
amortization 11,303 1,192 4,179 1,165 1,140 944 906
------------ ------------ ------------ ------------ ------------ ------------ ----------
Total expenses 17,804 1,963 8,705 4,694 4,114 3,359 3,282
------------ ------------ ------------ ------------ ------------ ------------ ----------
Operating income 56,317 5,536 22,276 7,786 5,417 3,007 2,907
Interest expense 12,991 1,371 11,260 4,516 3,559 3,460 3,550
Interest and other income 584 12 572 138 90 115 115
------------ ------------ ------------ ------------ ------------ ------------ ----------
Net income (loss) before
provision (benefit) in
lieu of income taxes $ 43,910 $ 4,177 $ 11,588 $ 3,408 $ 1,948 $ (338) $ (528)
Provision (benefit) in lieu
of income taxes - - 4,563 1,268 726 (93) (151)
------------ ------------ ------------ ------------ ------------ ------------ ----------
Net Income (loss) $ 43,910 $ 4,177 $ 7,025 $ 2,140 $ 1,222 $ (245) $ (377)
============ ============ ============ ============ ============ ============ ==========
Basic and Diluted Net
Income (loss) Per Limited
Partner Unit(2) $ 1.43 $ 0.14 $ 0.40 $ 0.12 $ 0.07 $ (0.01) $ (0.02)
============ ============ ============ ============ ============ ============ ==========
Weighted Average Number
of Limited Partner
Units Outstanding 30,088,858 30,088,858 17,003,858 17,003,858 17,003,858 17,003,858 17,003,858
============ ============ ============ ============ ============ ============ ==========
(Financial data continued on the next page. See footnotes on next page.)
21
Year November 23, January 1,
Ended 1998 to 1998 to Year Ended December 31,
December 31, December 31, November 22, -------------------------------------------------------
1998(1) 1998 1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ ------------ ------------ ----------
(Pro forma) (Predecessor) (Predecessor)
(Unaudited) (in thousands, except barrel amounts)
Balance Sheet Data:
(at end of period):
Working capital(3) $ 17,099 $ 17,099 N/A $ 10,962 $ 12,087 $ 9,579 $ 4,734
Total assets 610,208 610,208 N/A 149,619 122,557 82,076 62,847
Related party debt
Short-term 10,790 10,790 N/A 8,945 9,501 6,524 -
Long-term - - N/A 28,531 31,811 32,095 35,854
Total debt(3) 184,750 184,750 N/A 18,000 - - -
Partners' Equity 277,643 277,643 N/A - - - -
Combined Equity - - N/A 5,975 3,835 2,613 2,858
Other Data:
EBITDA(4) $ 68,204 $ 6,740 $ 27,027 $ 9,089 $ 6,647 $ 4,066 $ 3,928
Maintenance capital
expenditures(5) 1,679 200 1,479 678 1,063 571 274
Operating Data:
Volumes (barrels per day):
Tariff(6) 124,500 110,200 113,700 - - - -
Margin(7) 49,200 50,900 49,100 - - - -
-------- -------- -------- ------- -------- ------- -------
Total pipeline 173,700 161,100 162,800 - - - -
======== ======== ======== ======= ======== ======= =======
Lease gathering(8) 112,900 126,200 87,100 71,400 58,500 45,900 29,600
Bulk purchases(9) 97,900 133,600 94,700 48,500 31,700 10,200 -
Terminal throughput(10) 79,800 61,900 81,400 76,700 59,800 42,500 28,900
- ----------------------
(1) The unaudited selected pro forma financial and operating data for the year
ended December 31, 1998, is based on the historical financial statements of
the Partnership, the Predecessor and Wingfoot. 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, the Predecessor acquired the All American Pipeline
and SJV Gathering system from Goodyear for approximately $400 million. The
pro forma selected financial data reflects certain pro forma adjustments to
the historical results of operations as if the Partnership had been formed
and the Acquisition had taken place on January 1, 1998. The pro forma
adjustments include: (i) pro forma depreciation and amortization expense
based on the purchase price of the Wingfoot assets by the Predecessor; (ii)
the elimination of interest expense on loans from Goodyear to Wingfoot as
all such debt was extinguished in connection with the Acquisition; (iii)
the reduction in compensation and benefits expense due to the termination
of personnel in connection with the Acquisition; (iv) the elimination of
interest expense of the Predecessor related to debt owed to Plains
Resources as such debt was extinguished in connection with the
Transactions; (v) pro forma interest on debt assumed by the Partnership on
the closing date of the IPO; and (vi) the elimination of income tax expense
as income taxes will be borne by the partners and not the Partnership. The
pro forma adjustments do not include approximately $0.9 million of general
and administrative expenses that the General Partner believes will be
incurred by the Partnership as a result of its being a separate public
entity.
(2) Basic and diluted net income (loss) per Unit for the Partnership is
computed by dividing the limited partners' 98% interest in net income by
the number of outstanding Common and Subordinated Units. For periods prior
to November 23, 1998, such units are equal to the Common and Subordinated
Units received by the General Partner in exchange for the assets
contributed to the Partnership
(3) Excludes intercompany debt.
(4) EBITDA means earnings before interest expense, income taxes, depreciation
and amortization. EBITDA provides additional information for evaluating the
Partnership's ability to make the Minimum Quarterly Distribution and is
presented solely as a supplemental measure. EBITDA is not a measurement
presented in accordance with generally accepted accounting principles
("GAAP") and is not intended to be used in lieu of GAAP presentations of
results of operations and cash provided by operating activities. The
Partnership's EBITDA may not be comparable to EBITDA of other entities as
other entities may not calculate EBITDA in the same manner as the
Partnership.
(5) 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 the Partnership's existing capacity, whether
through construction or acquisition, are not considered maintenance capital
22
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.
(6) Represents crude oil deliveries on the All American Pipeline for the
account of third parties.
(7) Represents crude oil deliveries on the All American Pipeline and the SJV
Gathering System for the account of affiliated entities
(8) Represents barrels of crude oil purchased at the wellhead, including
volumes which would have been purchased under the Crude Oil Marketing
Agreement.
(9) Represents barrels of crude oil purchased at collection points, terminals
and pipelines.
(10) Represents total crude oil barrels delivered from the Cushing Terminal and
the Ingleside Terminal
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion of the financial condition and results of
operations for the Partnership and its predecessor entities should be read in
conjunction with the historical consolidated and combined financial statements
and notes thereto of the Partnership and the Plains Midstream Subsidiaries
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.
General
The Partnership is a limited partnership which was formed in the third
quarter of 1998 to acquire and operate the midstream crude oil business and
assets of Plains Resources. The Partnership is engaged in interstate and
intrastate crude oil pipeline transportation and crude oil terminalling and
storage activities and gathering and marketing activities. The Partnership's
operations are primarily concentrated in California, Texas, Oklahoma, Louisiana
and the Gulf of Mexico. The historical results of operations discussed below are
derived from the historical financial statements of the Partnership and the
Predecessor included elsewhere herein.
Pipeline Operations. The activities from pipeline operations generally
consist of transporting third-party volumes of crude oil for a tariff ("Tariff
Activities") 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 ("Margin Activities").
Tariffs on the All American Pipeline vary by receipt point and delivery point.
Tariffs for OCS crude oil delivered to California markets averaged $1.41 per
barrel and tariffs for OCS volumes delivered to West Texas were $2.96 per barrel
as of December 31, 1998. Tariffs for San Joaquin Valley crude oil delivered to
West Texas were $1.25 per barrel as of December 31, 1998. 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. As is common with most merchant activities, the
ability of the Partnership 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 the price paid and other costs incurred in the purchase of crude oil and
the price at which it sells crude oil. The Partnership is well positioned to
take advantage of these price differentials due to its ability to move purchased
volumes on the All American Pipeline. The Partnership combines 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 the
Cushing Terminal. Gross margin from the Partnership's gathering and marketing
activities is dependent on the Partnership's ability to sell crude oil at a
price in excess of the 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.
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.
The Partnership believes that the combination of its terminalling and storage
activities and gathering and marketing activities provides a counter-cyclical
balance which has a stabilizing effect on the Partnership's operations and cash
flow.
As the Partnership purchases crude oil, it establishes 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
23
on the NYMEX. Through these transactions, the Partnership seeks to maintain a
position that is substantially balanced between crude oil purchases and sales
and future delivery obligations. The Partnership purchases crude oil on both a
fixed and floating price basis. As fixed price barrels are purchased, the
Partnership enters 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, the Partnership matches
those contracts with similar type sales agreements with its customers, or
likewise establishes a hedge position using the NYMEX futures market. From time
to time, the Partnership will enter into arrangements which will expose it 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. The Partnership's policy is only to purchase crude oil for which it
has a market and to structure its sales contracts so that crude oil price
fluctuations do not materially affect the gross margin which it receives. The
Partnership does 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 the Partnership to indeterminable losses.
The Partnership
Analysis of Pro Forma Results of Operations
The pro forma results of operations discussed below are derived from the
historical financial statements of the Partnership, Wingfoot (which reflect the
historical operating results of the All American Pipeline and the SJV Gathering
System) and the Predecessor, certain of which are included elsewhere herein.
Commencing July 30, 1998, (the date of the 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. The pro forma results of operations
reflect certain pro forma adjustments to the historical results of operations as
if the Partnership had been formed and the acquisition of the All American
Pipeline and the SJV Gathering System had taken place on January 1, 1997. The
pro forma adjustments include: (i) pro forma depreciation and amortization
expense based on the purchase price of the Wingfoot assets by the Predecessor;
(ii) the elimination of interest expense on loans from Goodyear to Wingfoot as
all such debt was extinguished in connection with the Acquisition, (iii) the
reduction in compensation and benefits expense due to the termination of
personnel in connection with the Acquisition; (iv) the elimination of interest
expense of the Predecessor related to debt owed to Plains Resources as such debt
was extinguished in connection with the Transactions; (v) pro forma interest on
debt assumed by the Partnership on the Closing Date and (vi) the elimination of
income tax expense as income taxes will be borne by the partners and not the
Partnership. The pro forma adjustments do not include approximately $0.9 million
of general and administrative expenses for the years ended December 31, 1998 and
1997, respectively, that the General Partner believes will be incurred by the
Partnership as a result of its being a separate public entity.
Year Ended December 31, 1998 and 1997
The following table sets forth certain pro forma financial and operating
information of the Partnership for the periods presented.
Year Ended
December 31,
--------------------------------
1998 1997
------------- --------------
(in thousands)
(pro forma)
Operating Results:
Revenues $ 1,568,853 $ 1,746,491
=========== ===========
Gross margin
Pipeline $ 50,893 $ 70,078
Terminalling and storage and gathering and marketing 23,228 14,131
----------- -----------
Total 74,121 84,209
General and administrative expense (6,501) (6,182)
----------- -----------
Gross profit $ 67,620 $ 78,027
=========== ===========
Net income (loss) $ 43,910 $ (10,097)
=========== ===========
Average Daily Volumes (barrels)
Pipeline tariff activities 125 165
Pipeline margin activities 49 30
----------- -----------
Total 174 195
=========== ===========
Lease gathering 113 94
Bulk purchases 98 49
Terminal throughput 80 77
24
The following analysis compares the pro forma results of the Partnership
for the years ended December 31, 1998 and 1997.
For the year ended December 31, 1998, the Partnership's net income was
$43.9 million on total revenue of $1.6 billion compared to a net loss for the
year ended December 31, 1997 of $10.1 million on total revenue of $1.7 billion.
The pro forma net loss for the year ended December 31, 1997 includes a non-cash
impairment charge of $64.2 million related to the writedown of pipeline assets
and linefill by Wingfoot in connection with the sale of Wingfoot by Goodyear to
the General Partner. Based on the Partnership's purchase price allocation to
property and equipment and pipeline linefill, an impairment charge would not
have been required had the Partnership actually acquired Wingfoot effective
January 1, 1997. Excluding this impairment charge, the Partnership's pro forma
net income for 1997 would have been $54.1 million. The Partnership reported
gross margin (revenues less direct expenses of purchases, transportation,
terminalling and storage and other operating and maintenance expenses) of $74.1
million for the year ended December 31, 1998, reflecting a 12% decrease from the
$84.2 million reported for the same period in 1997. Gross profit (gross margin
less general and administrative expense) decreased 13% to $67.6 million for the
year ended December 31,1998 as compared to $78.0 million for the same period in
1997.
Pipeline Operations. Tariff revenues were $57.5 million for the year ended
December 31, 1998, a 30% decline from the $82.1 million reported for the same
period in 1997. This decrease in tariff revenues resulted primarily from a 24%
decrease in tariff transport volumes from 165,000 barrels per day for the year
ended December 31, 1997 to 125,000 barrels per day for the same period in 1998
due to a decline in average daily production from the Santa Ynez field. Most of
the production loss from the Santa Ynez field was of volumes that had been
previously transported to West Texas at an average tariff of $2.83 per barrel.
Volumes related to Margin Activities increased by 63% to an average of
approximately 49,000 barrels per day. The margin between revenue and direct cost
of crude purchased decreased from $17.6 million for the year ended December 31,
1997 to $14.5 million for the same period in 1998 as a result of a decline in
margins between prices paid in California and prices received in West Texas.
The following table sets forth All American Pipeline average deliveries per
day within and outside California for the periods presented.
Year Ended
December 31,
-----------------------
1998 1997
--------- ---------
(in thousands)
(pro forma)
Deliveries:
Average daily volumes (barrels):
Within California 113 127
Outside California 61 68
--- ---
Total 174 195
=== ===
Terminalling and Storage Activities and Gathering and Marketing Activities.
The Partnership reported gross margin of $23.2 million from its terminalling and
storage activities and gathering and marketing activities for the year ended
December 31, 1998, reflecting a 64% increase over the $14.1 million reported for
the same period in 1997. Including interest expense associated with contango
inventory transactions, gross margin for the year ended December 31, 1998 was
$22.5 million, representing an increase of approximately 70% over the 1997
amount. The increase in gross margin was primarily attributable to an increase
in the volumes gathered and marketed, principally in West Texas, Louisiana and
the Gulf of Mexico of approximately 20% to 113,000 barrels per day for the year
ended December 31, 1998 from 94,000 barrels per day during the same period in
1997. The balance of the increase in gross margin was a result of an increase in
bulk purchases.
Expenses. Operations and maintenance expenses included in cost of sales and
operations (generally property taxes, electricity, fuel, labor, repairs and
certain other expenses) decreased to $24.9 million for the year ended December
31, 1998 from $32.5 million for the comparable period in 1997. This decrease was
a function both of variable costs that decline with reduced transportation
volumes and average miles transported per barrel. Operations and maintenance
expenses are included in the determination of gross margin. General and
administrative expenses increased approximately $0.3 million to $6.5 million for
the year ended December 31, 1998 compared to $6.2 million for the same period in
1997. Such increase was primarily related to additional personnel hired to
further expand marketing activities. Depreciation and amortization expense was
$11.3 million for the year ended December 31, 1998 compared to $11.0 million for
the 1997 comparative period. The increase is due primarily to the addition of
trucking equipment. Interest expense was $13.0 million for the year ended
December 31, 1998 compared to $13.1 million for 1997.
25
Analysis of Historical Results of Operations
On November 23, 1998, the Partnership completed the IPO and the
Transactions whereby the Partnership became the successor to the business of the
Predecessor. The historical results of operations discussed below are derived
from the historical financial statements of the Partnership for the period from
November 23, 1998, through December 31, 1998, and the combined financial
statements of the Plains Midstream Subsidiaries 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 the 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. The Partnership and the Predecessor are referred to for purposes of
this analysis of historical results as the "Partnership".
Three Years Ended December 31, 1998
For 1998, the Partnership reported net income before taxes of $15.8 million
on total revenue of $1.1 billion compared to net income before taxes for 1997 of
$3.4 million on total revenue of $752.5 million and net income before taxes for
1996 of $1.9 million on total revenue of $531.7 million. Results for the year
ended December 31, 1998 include activities of the All American Pipeline and SJV
Gathering System since July 30, 1998 (the date of acquisition from Goodyear).
The following table sets forth certain financial and operating information
of the Partnership for the periods presented:
Year Ended December 31,
--------------------------------------------------
1998 1997 1996
-------------- -------------- --------------
(in thousands)
Operating Results:
Revenues $ 1,129,689 $ 752,522 $ 531,698
=========== ========= =========
Gross margin
Pipeline $ 16,768 $ - $ -
Terminalling and storage
and gathering and marketing 21,712 12,480 9,531
----------- --------- ---------
Total 38,480 12,480 9,531
General and administrative expense (5,297) (3,529) (2,974)
----------- --------- ---------
Gross profit $ 33,183 $ 8,951 $ 6,557
=========== ========= =========
Net Income $ 11,202 $ 2,140 $ 1,222
=========== ========= =========
Average Daily Volumes (barrels)
Pipeline tariff activities 113 - -
Pipeline margin activities 50 - -
----------- --------- ---------
Total 163 - -
=========== ========= =========
Lease gathering 88 71 59
Bulk purchases 95 49 32
Terminal throughput 80 77 59
Pipeline Operations. As noted above, the results of operations of the
Partnership includes approximately five months of operations of the All American
Pipeline and the SJV Gathering System which were acquired effective July 30,
1998. Tariff revenues for this period were $19.0 million and are primarily
attributable to transport volumes from the Santa Ynez field (approximately
65,300 barrels per day) and the Point Arguello field (approximately 24,300
barrels per day). The margin between revenue and direct cost of crude purchased
was approximately $3.9 million. Operations and maintenance expenses were $6.1
million.
The following table sets forth the All American Pipeline average deliveries
per day within and outside California from July 30, 1998 through December 31,
1998 (in thousands).
Deliveries:
Average daily volumes (barrels):
Within California 111
Outside California 52
---------
Total 163
=========
Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage and gathering and marketing
activities was $21.7 million for the year ended December 31, 1998, reflecting a
74% increase over the $12.5 million reported for the 1997 period and an
approximate 128% increase over the $9.5 million reported for 1996. Including
interest expense associated with contango inventory transactions, gross margin
for 1998 was $21.0 million, representing an increase
26
of approximately 81% over the 1997 amount. The Partnership did not have any
material contango inventory transactions in 1996. The increase in gross margin
was primarily attributable to an increase in the volumes gathered and marketed
in West Texas, Louisiana and the Gulf of Mexico and activities at the Cushing
Terminal.
Total general and administrative expenses were $5.3 million for the year
ended December 31, 1998, compared to $3.5 million and $3.0 million for 1997 and
1996, respectively. Such increases were primarily attributable to increased
personnel as a result of the continued expansion of the Partnership's
terminalling and storage activities and gathering and marketing activities as
well as general and administrative expenses associated with the addition of the
All American Pipeline and the SJV Gathering System. Depreciation and
amortization was $5.4 million in 1998, $1.2 million in 1997 and $1.1 million in
1996. The increase is due the acquisition of the All American Pipeline and the
SJV Gathering System in 1998.
Interest expense was $12.6 million in 1998, $4.5 million in 1997 and $3.6
million in 1996. The increase in 1998 is due to interest associated with the
debt incurred for the acquisition of the All American Pipeline and the SJV
Gathering System. Interest expense in 1997 and 1996 is comprised principally of
interest charged to the Predecessor by Plains Resources for amounts borrowed to
construct the Cushing Terminal in 1993 and subsequent capital additions,
including the Ingleside Terminal. The interest rate on the Cushing Terminal
construction loan was 10.25%. Interest expense also includes interest incurred
in connection with contango inventory transactions of $0.8 million in 1998 and
$.9 million in 1997.
The Predecessor is included in the consolidated federal income tax return
of Plains Resources. Federal income taxes are calculated as if the Predecessor
had filed its return on a separate company basis utilizing a federal statutory
rate of 35%. The Predecessor reported a total tax provision of approximately
$4.6 million, $1.3 million and $0.7 million for the period from January 1, 1998
to November 22, 1998 and for the years ended December 31, 1997 and 1996,
respectively.
Capital Resources, Liquidity and Financial Condition
Concurrently with the closing of the IPO, the Partnership entered into the
Bank Credit Agreement that includes the Term Loan Facility and the Revolving
Credit Facility. The Partnership may borrow up to $50 million under the
Revolving Credit Facility for acquisitions, capital improvements, working
capital and general business purposes.
The Term Loan Facility bears interest at the Partnership's option at either
(i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable
margin. Borrowings under the Revolving Credit Facility bear interest at the
Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve-
adjusted LIBOR plus an applicable margin. The Partnership incurs a commitment
fee on the unused portion of the Revolving Credit Facility.
At December 31, 1998, $175 million was outstanding under the Term Loan
Facility, which amount represents indebtedness assumed from the General Partner.
The Partnership has two 10-year interest rate swaps (each of which can be
terminated by the counterparty at the end of the seventh year) aggregating $175
million which fix the LIBOR portion of the interest rate (not including the
applicable margin) at a weighted average rate of approximately 5.24%. 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 2000. All borrowings for working
capital purposes outstanding under the Revolving Credit Facility must be reduced
to no more than $8 million for at least 15 consecutive days during each fiscal
year. At December 31, 1998, there were no amounts outstanding under the
Revolving Credit Facility. The Bank Credit Agreement is collateralized by a lien
on substantially all of the assets of the Partnership.
Simultaneously with the IPO, Marketing entered into a $175 million letter
of credit and borrowing facility which replaced an existing facility. The
purpose of the Letter of Credit Facility is to provide (i) standby letters of
credit to support the purchase and exchange of crude oil for resale and (ii)
borrowings to finance crude oil inventory which has been hedged against future
price risk or designated as working inventory. The Letter of Credit Facility is
collateralized by a lien on substantially all of the assets of the Partnership.
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 current assets and current liabilities of the Partnership
primarily crude oil inventory and accounts receivable and accounts payable
related to the purchase and sale of crude oil. At December 31, 1998, the
borrowing base under the Letter of Credit Facility was approximately $175
million.
The Letter of Credit Facility has a $40 million sublimit for borrowings to
finance crude oil purchased in connection with operations at the Partnership's
crude oil terminal and storage facilities. All purchases of crude oil inventory
financed are required to be hedged against future price risk on terms acceptable
to the lenders. At December 31, 1998, approximately $9.8 million was outstanding
under the sublimit.
27
Letters of credit under the Letter of Credit Facility are generally issued
for up to 70 day periods. Borrowings bear interest at the Partnership's option
at either (i) the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the
applicable margin. The Partnership incurs a commitment fee on the unused portion
of the borrowing sublimit under the Letter of Credit Facility and an issuance
fee for each letter of credit issued. The Letter of Credit Facility expires July
31, 2001. At December 31, 1998, there were outstanding letters of credit of
approximately $62 million issued under the Letter of Credit Facility.
Both the Letter of Credit Facility and the Bank Credit Agreement contain a
prohibition on distributions on, or purchases or redemptions of, Units if any
Default or Event of Default (as defined) is continuing. In addition, both
facilities contain various covenants limiting the ability of the Partnership to
(i) incur indebtedness, (ii) grant certain liens, (iii) sell assets in excess of
certain limitations, (iv) engage in transactions with affiliates, (v) make
investments, (vi) enter into hedging contracts and (vii) enter into a merger,
consolidation or sale of its assets. In addition, the terms of the Letter of
Credit Facility and the Bank Credit Agreement require the Partnership to
maintain (i) a Current Ratio (as defined) of at least 1.0 to 1.0; (ii) a Debt
Coverage Ratio (as defined) which is not greater than 5.0 to 1.0; (iii) an
Interest Coverage Ratio (as defined) which is not less than 3.0 to 1.0; (iv) a
Fixed Charge Coverage Ratio (as defined) which is not less than 1.25 to 1.0; and
(v) a Debt to Capital Ratio (as defined) of not greater than .60 to 1.0. In both
the Letter of Credit Facility and the Bank Credit Agreement, a Change in Control
(as defined) of Plains Resources or the General Partner constitutes an Event of
Default.
The Partnership will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
partner. Available Cash is generally defined as all cash and cash equivalents
of the Partnership on hand at the end of each quarter less reserves established
by the General partner for future requirements. Distributions of Available Cash
to holders of Subordinated units are subject to the prior rights of holders of
Common Units to receive the minimum quarterly distribution ("MQD") for each
quarter during the Subordination Period (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 Subordination 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), the General Partner will receive distributions
which are generally equal to 15%, then 25% and then 50% of the distributions of
Available Cash that exceed the MQD or Target Distribution Level. The Target
Distribution Levels are based on the amounts of Available Cash from the
Partnership's 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.
On February 12, 1999, the Partnership paid a cash distribution of $0.193
per unit on its outstanding Common Units and Subordinated Units. The $5.8
million distribution was paid to Unitholders of record at the close of business
on January 29, 1999. A distribution of approximately $118,000 was paid to the
General Partner. The distributions represented a partial quarterly distribution
for the 39-day period from November 23, 1998, the closing of the IPO, through
December 31, 1998.
Commitments
Historically, capital expenditures for the Partnership have not been
significant. Due to the relatively recent construction of the All American
Pipeline, the SJV Gathering System and the Cushing Terminal, material
maintenance capital expenditures have not been required, and the majority of
capital expenditures have been associated with expansion opportunities. While
the actual level of maintenance capital expenditures will vary from year to
year, the Partnership expects such expenditures to average approximately $2
million to $4 million annually for the next several years. It is anticipated
that such maintenance capital expenditures will be funded from cash flow
generated by operating activities.
The Partnership has entered into a turnkey contract to construct an
additional one million barrels of tankage at the Cushing Terminal, expanding its
existing tank capacity by 50% to three million barrels. Construction of the
expansion project began in September 1998 and is expected to be completed in the
second quarter of 1999 at a total cost of approximately $10 million.
Approximately $4.2 million of such cost was incurred in 1998. It is anticipated
that the remaining expenditures for the expansion will be funded from borrowings
under the Revolving Credit Facility. To date, the Partnership has no material
commitments to fund additional capital expenditures.
28
The Partnership owns approximately 5.0 million barrels of crude oil that is
used to maintain the All American Pipeline's linefill requirements. The
Partnership has amended its tariff with the FERC to require third party shippers
to buy linefill from the Partnership and replenish the linefill when their
movement of crude oil on the All American Pipeline is completed. Accordingly,
the Partnership does not anticipate large variations in the amounts of linefill
provided by the Partnership in the future.
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 is effective for all
fiscal years beginning after June 15, 1999. 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 it is, the type of hedge
transaction. For fair-value hedge transactions in which the Partnership is
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 the Partnership is 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. SFAS 133 is required to be applied to
financial statements issued by the Partnership beginning in 2000. The
Partnership has not yet determined the effect that the adoption of SFAS 133 will
have on its results of operations or financial position.
In November 1998, the Emerging Issues Task Force ("EITF") released Issue
No. 98-10, "Accounting for Energy Trading and Risk Management Activities". EITF
98-10 deals with entities that enter into derivatives and other third-party
contracts for the purchase and sale of a commodity in which they normally do
business (for example, crude oil and natural gas). The EITF reached a consensus
that energy trading contracts should be measured at fair value, determined as of
the balance sheet date, with the gains and losses included in earnings and
separately disclosed in the financial statements or footnotes thereto. The EITF
acknowledged that determining whether or when an entity is involved in energy
trading activities is a matter of judgment that depends on the relevant facts
and circumstances. As such, certain factors or indicators have been identified
by the EITF which should be considered in evaluating whether an operation's
energy contracts are entered into for trading purposes. EITF 98-10 is required
to be applied to financial statements issued by the Partnership beginning in
1999. The adoption of this consensus is not expected to have a material impact
on the Partnership's results of operations or financial position.
Year 2000
Year 2000 Issue. Some software applications, hardware and equipment and
embedded chip systems identify dates using only the last two digits of the year.
These products may be unable to distinguish between dates in the Year 2000 and
dates in the year 1900. That inability (referred to as the "Year 2000" issue),
if not addressed, could cause applications, equipment or systems to fail or
provide incorrect information after December 31, 1999, or when using dates after
December 31, 1999. This in turn could have an adverse effect on the Partnership,
because the Partnership directly depends on its own applications, equipment and
systems and indirectly depends on those of other entities with which the
Partnership must interact.
Compliance Program. In order to address the Year 2000 issues, the
Partnership is participating in the Year 2000 project which Plains Resources has
implemented for all of its business units. A project team has been established
to coordinate the six phases of this Year 2000 project to assure that key
automated systems and related processes will remain functional through Year
2000. Those phases include: (i) awareness, (ii) assessment, (iii) remediation,
(iv) testing, (v) implementation of the necessary modifications and (vi)
contingency planning. The key automated systems consist of (a) financial systems
applications, (b) hardware and equipment, (c) embedded chip systems and (d)
third-party developed software. The evaluation of the Year 2000 issue includes
the evaluation of the Year 2000 exposure of third parties material to the
operations of the Partnership or any of its business units. Plains Resources
retained a Year 2000 consulting firm to review the operations of all of its
business units and to assess the impact of the Year 2000 issue on such
operations. Such review has been completed and the consultant's recommendations
are being utilized in the Year 2000 project.
The Partnership's State of Readiness. The awareness phase of the Year 2000
project has begun with a company-wide awareness program which will continue to
be updated throughout the life of the project. The portion of the assessment
phase related to financial systems applications has been substantially completed
and the necessary modifications and conversions are underway. The portion of the
assessment phase which will determine the nature and impact of the Year 2000
issue for hardware and equipment, embedded chip systems, and third-party
developed software is continuing. The Partnership has retained a Year 2000
consulting firm which is currently identifying and evaluating field equipment
which has embedded chip systems. The assessment phase of the project involves,
among other things, efforts to obtain representations and assurances from third
parties, including third party vendors, that
29
their hardware and equipment, embedded chip systems, and software being used by
or impacting the Partnership or any of its business units are or will be
modified to be Year 2000 compliant. To date, the responses from such third
parties are inconclusive. As a result, management cannot predict the potential
consequences if these or other third parties are not Year 2000 compliant. The
exposure associated with the Partnership's interaction with third parties is
currently being evaluated. Management expects that the remediation, testing and
implementation phases will be substantially completed by the third quarter of
1999.
Contingency Planning. As part of the Year 2000 project, the Partnership
will seek to determine which of its business activities may be vulnerable to a
Year 2000 disruption. Appropriate contingency plans will then be developed for
each "at risk" business activity to provide an alternative means of functioning
which minimizes the effect of the potential Year 2000 disruption, both
internally and on those with whom it does business. Such contingency plans are
expected to be completed by the fourth quarter of 1999.
Costs to Address Year 2000 Compliance Issues. Through December 31, 1998,
the Partnership has borne approximately $264,000 as its share of expenses for
the Year 2000 project. While the total cost to the Partnership of the Year 2000
project is still being evaluated, management currently estimates that the costs
to be incurred in 1999 and 2000 associated with assessing, testing, modifying or
replacing financial system applications, hardware and equipment, embedded chip
systems and third party developed software is between $350,000 and $450,000.
The Partnership expects to fund these expenditures with cash from operations or
borrowings. Based upon these estimates, the Partnership does not expect the
costs of its Year 2000 project to have a material adverse effect on its
financial position, results of operation or cash flows.
Risk of Non-Compliance. The major applications that pose the greatest Year
2000 risks for the Partnership if implementation of the Year 2000 compliance
program is not successful are the Partnership's financial systems applications
and the Partnership's SCADA computer systems and embedded chip systems in field
equipment. The potential problems if the Year 2000 compliance program is not
successful are disruptions of the Partnership's revenue gathering from and
distribution to its customers and vendors and the inability to perform its other
financial and accounting functions. Failures of embedded chip systems in field
equipment of the Partnership or its customers could disrupt the Partnership's
crude oil transportation, terminalling and storage activities and gathering and
marketing activities.
While the Partnership believes that its Year 2000 project will
substantially reduce the risks associated with the Year 2000 issue, there can be
no assurance that it will be successful in completing each and every aspect of
the project on schedule, and if successful, the project will have the expected
results. Due to the general uncertainty inherent in the Year 2000 issues, the
Partnership cannot conclude that its failure or the failure of third parties to
achieve Year 2000 compliance will not adversely affect its financial position,
results of operations or cash flows.
Item 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Partnership is exposed to various market risks, including volatility in
crude oil commodity prices and interest rates. To manage such exposure, the
Partnership monitors its inventory levels, current economic conditions and its
expectations of future commodity prices and interest rates when making decisions
with respect to risk management. The Partnership does not enter into derivative
transactions for speculative trading purposes. Substantially all the
Partnership's derivative contracts are exchanged or traded with major financial
institutions and the risk of credit loss is considered remote.
As the Partnership purchases crude oil, it establishes 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, the Partnership seeks to maintain a position that is substantially
balanced between crude oil purchases and sales and future delivery obligations.
From time to time, the Partnership enters into fixed price delivery contracts,
floating price collar arrangements, financial swaps and oil futures contracts as
hedging devices. To hedge the price exposure related to crude oil that the
Partnership is committed to purchase, the Partnership may sell futures contracts
and thereafter either (i) make physical delivery of such purchased crude oil
against the futures contract or (ii) buy a matching futures contract to unwind
its futures position and sell its crude oil to a customer. Such contracts may
expose the Partnership to the risk of financial loss in certain circumstances,
including instances where production is less than expected, the Partnership's
customers fail to purchase or deliver the contracted quantities of crude oil, or
a sudden, unexpected event materially affects crude oil prices. Such contracts
may also restrict the ability of the Partnership to benefit from unexpected
increases in crude oil prices. The Partnership's policy is generally to purchase
only crude oil for which it has a market and to structure its sales contracts so
that crude oil price fluctuations do not materially affect the gross margin
which it receives.
30
The Partnership has interest rate swaps for an aggregate notional principal
amount of $175 million which fix the LIBOR portion of the interest rate (not
including the applicable margin) on the Term Loan Facility. At December 31,
1998, the Partnership would be required to pay approximately $2.2 million to
terminate the interest rate swaps as of such date.
Commodity Price Risk
The fair value of outstanding derivative commodity instruments and the
change in fair value that would be expected from a 10 percent adverse price
change are shown in the table below:
Change in Fair
Fair Value from 10%
At December 31, 1998 Value Adverse Price Change
-------------------- ---------------- -----------------------
(in millions)
Crude oil
futures contracts $ 1.8 $(0.3)
The fair values of the futures contracts are based on quoted market prices
obtained from the NYMEX. 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 the Partnership's derivative
portfolio would typically change less than that shown in the table due to lower
volatility in out-month prices.
Additional details regarding accounting policy for these financial
statements are set forth in Note 1 to the Consolidated and Combined Financial
Statements.
Interest Rate Risk
The Partnership's debt instruments are sensitive to market fluctuations in
interest rates. The table below presents principal cash flows and the related
weighted average interest rates by expected maturity dates. The Partnership's
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, 1998. The carrying value of variable rate bank debt approximates
fair value as interest rates are variable, based on prevailing market rates.
December 31,
----------------------------------------------------------------------------
Expected Year of Maturity Fair
1999 2000 2001 2002 2003 Thereafter Total Value
--------- -------- -------- -------- -------- ------------ ----------- ---------
(dollars in millions)
Liabilities:
Short-term debt - variable rate $ 9.7 $ - $ - $ - $ - $ - $ 9.7 $ 9.7
Average interest rate 6.80%
Long-term debt - variable rate - - - - - 175.0 175.0 175.0
Average interest rate 6.75%
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required to be provided in this item is included in the
Consolidated and Combined Financial Statements of the Partnership and the Plains
Midstream Subsidiaries, including the notes thereto, attached hereto as pages
F-1 to F-20 and such information is incorporated herein by reference.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
31
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
Partnership Management
The General Partner manages and operates the activities of the Partnership.
The Unitholders do not directly or indirectly participate in the management or
operation of the Partnership or have actual or apparent authority to enter into
contracts on behalf of, or to otherwise bind, the Partnership. Notwithstanding
any limitation on its obligations or duties, the General Partner is liable, as
general partner of the Partnership, for all debts of the Partnership (to the
extent not paid by the Partnership), except to the extent that indebtedness or
other obligations incurred by the Partnership are made specifically non-recourse
to the General Partner. Whenever possible, the General Partner intends to make
any such indebtedness or other obligations non-recourse to the General Partner.
The General Partner recently appointed Arthur L. Smith to its Board of
Directors. Mr. Smith, who is neither an officer nor employee of the General
Partner nor a director, officer or employee of any affiliate of the General
Partner, serves on the Conflicts Committee, which has the authority to review
specific matters as to which the Board of Directors believes there may be a
conflict of interest in order to determine if the resolution of such conflict
proposed by the General Partner is fair and reasonable to the Partnership. An
additional independent director is expected to be appointed during the year to
serve on the General Partner's Board of Directors and the Conflicts Committee.
Any matters approved by the Conflicts Committee will be conclusively deemed to
be fair and reasonable to the Partnership, approved by all partners of the
Partnership and not a breach by the General Partner or its Board of Directors of
any duties they may owe the Partnership or the Unitholders. The Audit Committee,
comprised of Messrs. Smith and Robert V. Sinnott, reviews the external financial
reporting of the Partnership, recommends engagement of the Partnership's
independent public accountants and reviews the Partnership's procedures for
internal auditing and the adequacy of the Partnership's internal accounting
controls. The Compensation Committee, comprised of Messrs. Smith and Sinnott,
oversees compensation decisions for the officers of the General Partner as well
as the compensation plans described below.
As is commonly the case with publicly traded limited partnerships, the
Partnership does not directly employ any of the persons responsible for managing
or operating the Partnership. These functions are provided by employees of the
General Partner and Plains Resources.
Directors and Executive Officers of the General Partner
The following table sets forth certain information with respect to the
executive officers and members of the Board of Directors of the General Partner.
Executive officers and directors are elected annually and have held the
following positions with the General Partner since its formation in February
1998, except for Messrs. Sinnott and Smith who were appointed to the Board in
September 1998 and February 1999, respectively.
Name Age Position with General Partner
- --------------------------------- --- -----------------------------------------------------------------
Greg L. Armstrong 40 Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis 41 President, Chief Operating Officer and Director
Phillip D. Kramer 43 Executive Vice President and Chief Financial Officer
George R. Coiner 47 Senior Vice President
Michael R. Patterson 51 Senior Vice President, General Counsel and Secretary
Cynthia A. Feeback 41 Treasurer
Robert V. Sinnott 49 Director
Arthur L. Smith 46 Director
Greg L. Armstrong 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.
Harry N. Pefanis 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 is also
President of the Plains Midstream Subsidiaries.
32
Phillip D. Kramer 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 been 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 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.
Cynthia A. Feeback has been Assistant Treasurer and Controller of Plains
Resources since May 1998. She previously served Plains Resources as Controller
and Principal Accounting Officer from 1993 to 1998; Controller from 1990 to
1993; and Accounting Manager from 1988 to 1990.
Robert V. Sinnott has been Senior 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 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. 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, executive officers and persons who beneficially own more than ten
percent of a registered class of the Partnership's equity securities to file
with the SEC and the New York Stock Exchange initial reports of ownership and
reports of changes in ownership of such equity securities. Such persons are also
required to furnish the Partnership with copies of all Section 16(a) forms that
they file. Based solely upon a review of the copies of the forms furnished to
it, or written representations from certain reporting persons that no Forms 5
were required, the Partnership believes that during 1998 its officers and
directors complied with all filing requirements with respect to the
Partnership's equity securities.
Reimbursement of Expenses of the General Partner and its Affiliates
The General Partner does not receive any management fee or other
compensation in connection with its management of the Partnership. The General
Partner and its affiliates, including Plains Resources, performing services for
the Partnership are reimbursed for all expenses incurred on behalf of the
Partnership, including the costs of employee, officer and director compensation
and benefits properly allocable to the Partnership, and all other expenses
necessary or appropriate to the conduct of the business of, and allocable to,
the Partnership. The Partnership Agreement provides that the General Partner
will determine the expenses that are allocable to the Partnership in any
reasonable manner determined by the General Partner in its sole discretion.
Item 11. EXECUTIVE COMPENSATION
The Partnership was formed in September 1998 but conducted no business
until late November 1998. Mr. Armstrong, the General Partner's Chief Executive
Officer received no compensation for services to the Partnership in 1998. No
officer of the General Partner received compensation for services to the
Partnership in 1998 in amounts greater than $100,000.
Employment Agreement
Mr. Pefanis has an employment agreement with Plains Resources. Pursuant to
the employment agreement, Mr. Pefanis serves as President and Chief Operating
Officer of the General Partner as well as an Executive Vice President of Plains
Resources and is responsible for the overall operations of the General Partner
and the marketing operations of Plains Resources. 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 the General Partner. The employment agreement has an initial term,
commencing November 23, 1998, of three years subject to annual extensions and
includes confidentiality, nonsolicitation and noncompete provisions, which, in
general, will continue for 24 months following Mr. Pefanis' termination of
employment. The agreement provides for an annual base salary of $235,000,
subject to such increases as the Board of Directors of Plains Resources may
authorize from time to time. In
33
addition, Mr. Pefanis is eligible to receive an annual cash bonus to be
determined by the Board of Directors of Plains Resources. Mr. Pefanis
participates in the Long-Term Incentive Plan of the General Partner as described
below and is also entitled to participate in such other benefit plans and
programs as the General Partner may provide for its employees in general. 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 (i) his
highest rate of annual base salary and (ii) the largest annual bonus paid during
the three preceding years.
Long-Term Incentive Plan
The General Partner has adopted the Plains All American Inc. 1998 Long-Term
Incentive Plan (the "Long-Term Incentive Plan") for employees and directors of
the General Partner and its affiliates who perform services for the Partnership.
The Long-Term Incentive Plan consists of two components, a restricted unit plan
(the "Restricted Unit Plan") and a unit option plan (the "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 the 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 22, 1999, an aggregate of approximately 500,000 Restricted Units have been
granted to employees of the General Partner, including 60,000 and 30,000 units
granted to Messrs. Pefanis and Coiner, respectively. The Compensation Committee
may, in the future, determine to make additional grants under such 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 the 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
the General Partner in the open market, Common Units already owned by the
General Partner, Common Units acquired by the General Partner directly from the
Partnership or any other person, or any combination of the foregoing. The
General Partner will be entitled to reimbursement by the Partnership for the
cost incurred in acquiring such Common Units. If the Partnership issues 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
intended to serve as a means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity appreciation in respect
of the Common Units. Therefore, no consideration will be payable by the plan
participants upon receipt of the Common Units, and the Partnership will receive
no remuneration for such Units.
Unit Option Plan. The Unit Option Plan currently permits the grant of
options ("Unit Options") covering Common Units. No grants have been made under
the Unit Option Plan. The Compensation Committee may, in the future, determine
to make grants under such plan to employees and directors containing such terms
as the Committee shall determine.
Unit Options will 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, the General Partner will acquire Common
Units in the open market at a price equal to the then-prevailing price on the
principal national securities exchange upon which the Common Units are then
traded, or directly from the Partnership or any other person, or use Common
Units already owned by the General Partner, or any combination of the foregoing.
The General Partner will be entitled to reimbursement by the Partnership for the
difference between the cost incurred by the General Partner in acquiring such
Common Units and the proceeds received by the General Partner from an optionee
at the time of exercise. Thus, the cost of the Unit Options will be borne by the
Partnership. If the Partnership issues new Common Units upon exercise of the
Unit Options, the total number of Common Units outstanding will increase, and
the General Partner will remit to the Partnership the proceeds it received from
the optionee upon exercise of the Unit Option to the Partnership.
The Unit Option Plan has been designed to furnish additional compensation
to employees and directors and to align their economic interests with those of
Common Unitholders.
34
The 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 theretofore been made. The General Partner's Board of
Directors also has the right to alter or amend the Long-Term Incentive Plan or
any part thereof 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, the General Partner, at no cost to the Partnership, agreed to transfer
approximately 325,000 of its affiliates' Common Units to certain key employees
of the General Partner. Generally, approximately 72,000 of such Common Units
will 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, such Common Units will vest at the
time the Common Unit Arrearages for such year have been paid. In addition,
approximately 36,000 of such Common Units will 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. Any Common Units remaining unvested shall vest
upon, and in the same proportion as, the conversion of Subordinated Units to
Common Units. Notwithstanding the foregoing, all Common Units become vested if
Plains All American Inc. is removed as General Partner of the Partnership prior
to January 1, 2002. The compensation expense incurred in connection with these
grants will be funded by the General Partner, without reimbursement by the
Partnership. Of the 325,000 Common Units, 75,000 were allocated to Mr. Pefanis
and 50,000 were allocated to Mr. Coiner.
Management Incentive Plan
The General Partner has adopted the Plains All American Inc. Management
Incentive Plan (the "Management Incentive Plan"). The Management Incentive
Plan is designed to enhance the financial performance of the 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 the General Partner may amend or
change the Management Incentive Plan at any time. The General Partner is
entitled to reimbursement by the Partnership for payments and costs incurred
under the plan.
Compensation of Directors
Each director of the General Partner who is not an employee of the General
Partner (a "Non-employee Director") 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 the General Partner, are
otherwise compensated for their services to the General Partner and therefore
receive no separate compensation for their services as directors of the General
Partner.
35
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 22, 1999,
regarding the beneficial ownership of Units held by (i) each person known by the
General Partner to be the beneficial owner of 5% or more of the Units, (ii) each
director and executive officer of the General Partner and (iii) by all directors
and executive officers of the General Partner as a group.
Percentage Of Percentage of Percentage
Common Common Subordinated Subordinated Of Total
Units Units Units Units Units
Beneficially Beneficially Beneficially Beneficially Beneficially
Name of Beneficial Owner Owned Owned Owned Owned Owned
- -------------------------------------- --------------- -------------- ------------ ---------------- -------------
Plains All American Inc. (1) 6,974,239(2) 34.8% 10,029,619 100% 56.5%
Greg L. Armstrong 18,000 * - - *
Harry N. Pefanis 12,000 * - - *
Phillip D. Kramer 6,000 * - - *
George R. Coiner - - - - -
Michael R. Patterson 7,000 * - - *
Cynthia A. Feeback 500 * - - *
Robert V. Sinnott - - - - -
Arthur L. Smith 7,500 * - - *
All directors and executive officers
as a group (7 persons) 51,000 * - - *
- ---------------------
* Less than one percent
(1) The record holder of such Common Units and Subordinated Units is PAAI LLC,
a wholly owned subsidiary of Plains All American Inc., the General Partner
of the Partnership. Plains All American Inc. is a wholly owned subsidiary
of Plains Resources Inc. The address for each is 500 Dallas, Suite 700,
Houston, Texas 77002.
(2) Includes 325,000 Common Units to be transferred, subject to certain vesting
conditions, to certain key employees of the General Partner pursuant to
certain Transaction Grant Agreements.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Rights of the General Partner
The General Partner and its affiliates own 6,974,239 Common Units and
10,029,619 Subordinated Units, representing an aggregate 55.4% limited partner
interest in the Partnership. In addition, the General Partner owns an aggregate
2% general partner interest in the Partnership and the Partnership on a combined
basis. Through the General Partner's ability, as general partner, to manage and
operate the Partnership and the ownership of 6,974,239 Common Units and all of
the outstanding Subordinated Units by the General Partner and its affiliates
(effectively giving the General Partner the ability to veto certain actions of
the Partnership), the General Partner has the ability to control the management
of the Partnership.
Agreements Governing the Transactions
In connection with the Transactions, the Partnership, the General Partner
and certain other parties entered into the various documents and agreements to
effect the Transactions, including the vesting of assets in, and the assumption
of liabilities by, the Partnership, and the application of the proceeds of the
IPO. See Item 1. "Business - Initial Public Offering and Concurrent
Transactions".
Relationship with Plains Resources
General
The Partnership has extensive ongoing relationships with Plains Resources.
These relationships include (i) Plains Resources' wholly owned subsidiary,
Plains All American Inc., serving as General Partner of the Partnership, (ii) an
Omnibus Agreement, providing for the resolution of certain conflicts arising
from the conduct of the Partnership and Plains Resources of related businesses
and for the General Partner's indemnification of the Partnership for certain
matters and (iii) the Crude Oil Marketing Agreement with Plains Resources,
providing for the marketing of Plains Resources' crude oil production.
36
Transactions with Affiliates
On the Closing Date, the Partnership and Plains Resources Inc. entered into
the Crude Oil Marketing Agreement which provides for the marketing by the
Partnership of Plains Resources' crude oil production for a fee of $0.20 per
barrel. The Partnership paid Plains Resources approximately $4.1 for the
purchase of crude oil under such agreement for the period from November 23, 1998
to December 31, 1998, and recognized approximately $120,000 of profit for such
period.
Prior to the Crude Oil Marketing Agreement, the Plains Midstream
Subsidiaries marketed crude oil production of Plains Resources, its subsidiaries
and its royalty owners. The Plains Midstream Subsidiaries paid approximately
$83.4 million, $101.2 million and $100.5 million for the purchase of these
products for the period from January 1, 1998 to November 22, 1998 and the years
ended December 31, 1997 and 1996, respectively. In management's opinion, such
purchases were made at prevailing market rates. The Plains Midstream
Subsidiaries did not recognize a profit on the sale of the crude oil purchased
from Plains Resources.
The Partnership does not directly employ any persons to manage or operate
its business. These functions are provided by employees of the General Partner
and Plains Resources. The General partner does not receive a management fee or
other compensation in connection with its management of the Partnership. The
Partnership reimburses the 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 the
Partnership, and all other expenses necessary or appropriate to the conduct of
the business of, and allocable to the Partnership. The Partnership Agreement
provides that the General Partner will determine the expenses that are allocable
to the Partnership in any reasonable manner determined by the General Partner in
its sole discretion. Total costs reimbursed to the General Partner and Plains
Resources by the Partnership were approximately $0.5 million for the period from
November 23, 1998 to December 31, 1998. Such costs include, (I) allocated
personnel costs (such as salaries and employee benefits) of the personnel
providing such services, (ii) rent on office space allocated to the General
partner in Plains Resources' offices in Houston, Texas and (iii) 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, 1997 and 1996. 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.
Indemnity from the General Partner
In connection with the acquisition of the All American Pipeline and the SJV
Gathering System, Wingfoot agreed to indemnify the General Partner for certain
environmental and other liabilities. The indemnity is subject to limits of (i)
$10 million with respect to matters of corporate authorization and title to
shares, (ii) $21.5 million with respect to condition of rights of way, lease
rights and undisclosed liabilities and litigation and (iii) $30 million with
respect to environmental liabilities resulting from certain undisclosed and pre-
existing conditions. Wingfoot has no liability, however, until the aggregate
amount of losses, with respect to each such limit, is in excess of $1 million.
The indemnities will remain in effect for a two year period after the date of
the acquisition, with the exception of the environmental indemnity, which will
remain in effect for a period of three years after the date of the Acquisition.
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. The Partnership has also
agreed to be solely responsible for the cumulative aggregate amount of losses
resulting from an oil leak from the All American Pipeline that occurred in 1997
to the extent such losses do not exceed $350,000. Any costs in excess of
$350,000 will be applied to the $1 million deductible for the Wingfoot
environmental indemnity. The General Partner has agreed to indemnify the
Partnership for environmental and other liabilities to the extent it is
indemnified by Wingfoot.
Plains Resources has agreed to indemnify the Partnership for environmental
liabilities related to the assets of the Plains Midstream Subsidiaries
transferred to the Partnership 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 million.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(1) Financial Statements
The financial statements filed as part of this report are listed in the
"Index to Consolidated Financial Statements" on Page F-1 hereof.
37
(2) Exhibits
3.1 + --Second Amended and Restated Agreement of Limited Partnership of Plains All American
Pipeline, L.P. dated as of November 23, 1998.
3.2 + --Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as
of November 23, 1998.
3.3 + --Amended and Restated Agreement of Limited Partnership of All American Pipeline, L.P.
dated as of November 23, 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.
3.6 + --Articles of Conversion of All American Pipeline Company dated as of November 10, 1998.
10.1 + --Credit Agreement among All American Pipeline, L.P., Plains All American Pipeline, L.P., Plains Marketing, L.P.,
ING (U.S.) Capital Corporation and certain other banks dated as of November 17, 1998.
10.2 + --Amended and Restated Credit Agreement among Plains Marketing, L.P., Plains All American Pipeline, L.P.,
All American Pipeline, L.P., BankBoston, N.A., and certain other banks dated as of November 17, 1998.
10.3 + --Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other
parties dated as of November 23, 1998.
*10.4 + --Plains All American Inc., 1998 Long-Term Incentive Plan.
*10.5 + --Plains All American Inc., 1998 Management Incentive Plan.
*10.6 + --Employment Agreement between Plains Resources Inc. and Harry N. Pefanis dated as of November 23, 1998.
10.7 + --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.
10.8 + --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.
10.9 + --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).
10.10 --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).
38
*10.11 --Form of Transaction Grant Agreement (Deferred Payment) (incorporated by reference to Exhibit 10.11 to Registration
Statement, file No. 333-64107).
*10.12 --Form of Transaction Grant Agreement (Payment on Vesting) (incorporated by reference to Exhibit 10.12 to
Registration Statement, file No. 333-64107).
10.13 + --First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998
10.14 + --First Amendment dated as of March 18, 1999, to Credit Agreement among All American Pipeline, L.P., Plains All
American Pipeline, L.P., Plains Marketing, L.P., ING (U.S.) Capital Corporation and certain other banks.
10.15 + --First Amendment dated as of March 18, 1999, to Amended and Restated Credit Agreement among Plains Marketing,
L.P., Plains All American Pipeline, L.P., All American Pipeline, L.P., BankBoston, N.A. and certain other banks.
10.16 + --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.
21.1 --List of subsidiaries of the Partnership (incorporated by reference to Exhibit 21.1 to Registration Statement,
file No. 333-64107).
27.1 + --Financial Data Schedule
- ---------------------
+ Filed herewith
* Management contract or compensatory plan or arrangement
(b) Reports on Form 8-K
None
39
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.,
Its General Partner
Date: March 31, 1999 By: /s/ Phillip D. Kramer
------------------------------------------
Phillip D. Kramer,
Executive Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date: March 31, 1999 By: /s/ Greg L. Armstrong
------------------------------------------
Greg L. Armstrong, Chairman of the Board,
Chief Executive Officer and
Director of the General Partner
(Principal Executive Officer)
Date: March 31, 1999 By: /s/ Harry N. Pefanis
------------------------------------------
Harry N. Pefanis, President,
Chief Operating Officer and Director
of the General Partner
Date: March 31, 1999 By: /s/ Phillip D. Kramer
------------------------------------------
Phillip D. Kramer, Executive Vice
President and Chief Financial Officer
(Principal Financial Officer) of
the General Partner
Date: March 31, 1999 By: /s/ Cynthia A. Feeback
------------------------------------------
Cynthia A. Feeback, Treasurer
(Principal Accounting Officer) of the
General Partner
Date: March 31, 1999 By: /s/ Robert V. Sinnott
------------------------------------------
Robert V. Sinnott, Director of the General
Partner
Date: March 31, 1999 By: /s/ Arthur L. Smith
------------------------------------------
Arthur L. Smith, Director of the General
Partner
40
INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS Page
Report of Independent Accountants F-2
Consolidated and Combined Balance Sheets as of December 31, 1998 and 1997 (Predecessor) F-3
Consolidated and Combined Statements of Income:
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 years ended December 31, 1997 and 1996 (Predecessor) F-4
Consolidated and Combined Statements of Cash Flows:
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 years ended December 31, 1997 and 1996 (Predecessor) F-5
Consolidated Statement of Changes in Partners' Equity for the period from
inception (November 23, 1998) to December 31, 1998 F-6
Notes to Consolidated and Combined Financial Statements F-7
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
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 sheet and the related
consolidated statements of income, of changes in partners' equity and of cash
flows present fairly, in all material respects, the consolidated financial
position of Plains All American Pipeline, L.P. and subsidiaries (the
"Partnership") at December 31, 1998 and the consolidated results of their
operations and their cash flows for the period from inception (November 23,
1998) to December 31, 1998 in conformity with generally accepted accounting
principles. 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 audit. We conducted our audit of these
statements in accordance with generally accepted auditing standards 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 audit provides a
reasonable basis for the opinion expressed above.
In our opinion, the accompanying combined balance sheet and related combined
statements of income and of cash flows of the Plains Midstream Subsidiaries, the
predecessor entity of the Partnership, present fairly, in all material respects,
the combined financial position of the Plains Midstream Subsidiaries at December
31, 1997 and the combined results of their operations and their cash flows for
the period from January 1, 1998 to November 22, 1998 and the years ended
December 31, 1997 and 1996 in conformity with generally accepted accounting
principles. 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 generally accepted auditing standards 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, 1999
F-2
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
December 31,
-----------------------------
1998 1997
------------- --------------
(Predecessor)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 5,503 $ 2
Accounts receivable 119,514 96,319
Due from affiliates 3,022 -
Inventory 37,711 18,909
Prepaid expenses and other 1,101 197
-------- --------
Total current assets 166,851 115,427
-------- --------
PROPERTY AND EQUIPMENT
Crude oil pipeline, gathering and terminal assets 378,254 35,591
Other property and equipment 581 698
-------- --------
378,835 36,289
Less allowance for depreciation and amortization (799) (3,903)
-------- --------
378,036 32,386
-------- --------
OTHER ASSETS
Pipeline linefill 54,511 -
Other 10,810 1,806
-------- --------
$610,208 $149,619
======== ========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $135,713 $ 86,415
Interest payable 1,267 50
Due to affiliates 10,790 8,945
Notes payable 9,750 18,000
-------- --------
Total current liabilities 157,520 113,410
LONG-TERM LIABILITIES
Bank debt 175,000 -
Due to affiliates - 28,531
Payable in lieu of deferred taxes - 1,703
Other 45 -
-------- --------
Total liabilities 332,565 143,644
-------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 8)
COMBINED EQUITY - 5,975
-------- --------
PARTNERS' EQUITY
Common unit holders (20,059,239 units outstanding) 256,997 -
Subordinated unit holders (10,029,619 units outstanding) 19,454 -
General partner 1,192 -
-------- --------
277,643 -
-------- --------
$610,208 $149,619
======== ========
See notes to consolidated and combined financial statements.
F-3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
(in thousands, except unit and per unit data)
NOVEMBER 23, JANUARY 1,
1998 TO 1998 TO YEAR ENDED DECEMBER 31,
DECEMBER 31, NOVEMBER 22, ----------------------------
1998 1998 1997 1996
------------ ------------ ----------- ------------
(PREDECESSOR) (PREDECESSOR) (PREDECESSOR)
REVENUES $ 176,445 $ 953,244 $ 752,522 $ 531,698
COST OF SALES
AND OPERATIONS 168,946 922,263 740,042 522,167
---------- ---------- ---------- ----------
Gross Margin 7,499 30,981 12,480 9,531
---------- ---------- ---------- ----------
EXPENSES
General and administrative 771 4,526 3,529 2,974
Depreciation and amortization 1,192 4,179 1,165 1,140
---------- ---------- ---------- ----------
Total expenses 1,963 8,705 4,694 4,114
---------- ---------- ---------- ----------
Operating income 5,536 22,276 7,786 5,417
Interest expense 1,371 8,492 894 -
Related party interest expense - 2,768 3,622 3,559
Interest and other income 12 572 138 90
---------- ---------- ---------- ----------
Net income before provision
in lieu of income taxes 4,177 11,588 3,408 1,948
Provision in lieu of income taxes - 4,563 1,268 726
---------- ---------- ---------- ----------
NET INCOME $ 4,177 $ 7,025 $ 2,140 $ 1,222
========== ========== ========== ==========
BASIC AND DILUTED
NET INCOME PER
LIMITED PARTNER UNIT $ 0.14 $ 0.40 $ 0.12 $ 0.07
========== ========== ========== ==========
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING 30,088,858 17,003,858 17,003,858 17,003,858
========== ========== ========== ==========
See notes to consolidated and combined financial statements.
F-4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
NOVEMBER 23, JANUARY 1,
1998 TO 1998 TO YEAR ENDED DECEMBER 31,
DECEMBER 31, NOVEMBER 22, ----------------------------
1998 1998 1997 1996
------------ ------------ ----------- ------------
(PREDECESSOR) (PREDECESSOR) (PREDECESSOR)
CASH FLOWS FROM
OPERATING ACTIVITIES
Net income $ 4,177 $ 7,025 $ 2,140 $ 1,222
Items not affecting cash flows
from operating activities:
Depreciation and amortization 1,192 4,179 1,165 1,140
(Gain) loss on sale of
property and equipment - 117 (28) (34)
Change in payable in lieu of deferred taxes - 4,108 1,131 706
Other non cash items 45 - - -
Change in assets and liabilities, net of Acquisition:
Accounts receivable (10,203) 38,794 (10,415) (38,771)
Inventory (14,805) (3,336) (16,450) 435
Prepaid expenses and other (42) (1,296) (39) 41
Accounts payable and
other current liabilities 33,008 (30,511) 9,577 35,994
Interest payable 1,267 (39) 50 -
Pipeline linefill (6,247) 2,343 - -
---------- ---------- ---------- ----------
Net cash provided by (used in)
operating activities 8,392 21,384 (12,869) 733
---------- ---------- ---------- ----------
CASH FLOWS FROM
INVESTING ACTIVITIES
Acquisition (see Note 2): - (394,026) - -
Additions to property and equipment (2,887) (5,528) (678) (3,346)
Disposals of property and equipment - 8 85 97
Additions to other assets (202) (65) (1,261) (36)
---------- ---------- ---------- ----------
Net cash used in investing activities (3,089) (399,611) (1,854) (3,285)
---------- ---------- ---------- ----------
CASH FLOWS FROM
FINANCING ACTIVITIES
Advances from (payments to) affiliates (1,174) 3,349 (3,679) 2,759
Debt issue costs incurred in connection
with Acquisition (see Note 2) - (9,938) - -
Proceeds from initial public offering (see Note 1) 244,690 - - -
Distributions upon formation (see Note 1) (241,690) - - -
Payment of formation costs (3,000) - - -
Cash balance at formation 224 - - -
Proceeds from long-term debt - 331,300 - -
Proceeds from short-term debt 1,150 30,600 39,000 -
Principal payments of long-term debt - (39,300) - -
Principal payments of short-term debt - (40,000) (21,000) -
Capital contribution from Parent - 113,700 - -
Dividend to Parent - (3,557) - -
---------- ---------- ---------- ----------
Net cash provided by financing activities 200 386,154 14,321 2,759
---------- ---------- ---------- ----------
Net increase (decrease) in cash
and cash equivalents 5,503 7,927 (402) 207
Cash and cash equivalents, beginning of period - 2 404 197
---------- ---------- ---------- ----------
Cash and cash equivalents, end of period $ 5,503 $ 7,929 $ 2 $ 404
========== ========== ========== ==========
See notes to consolidated and combined financial statements.
F-5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998
(in thousands)
Total
General Partners'
Common Units Subordinated Units Partner Equity
---------------------- ------------------- --------- ----------
Units Amount Units Amount Amount Amount
---------- --------- --------- -------- --------- ----------
Issuance of units to public 13,085 $241,690 $ - $ - $ 241,690
Contribution of assets and
debt assumed 6,974 108,253 10,030 155,680 9,533 273,466
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 2,729 1,364 84 4,177
---------- --------- --------- -------- --------- ----------
BALANCE AT
DECEMBER 31, 1998 20,059 $ 256,997 10,030 $ 19,454 $ 1,192 $ 277,643
========== ========= ========= ======== ========= ==========
See notes to consolidated and combined financial statements.
F-6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 1--Organization and Significant Accounting Policies
Organization
Plains All American Pipeline, L.P. (the "Partnership") is a Delaware
limited partnership that was formed in the third quarter of 1998, to acquire and
operate the midstream crude oil business and assets of Plains Resources Inc.
("Plains Resources") and its wholly owned subsidiaries (the "Plains Midstream
Subsidiaries" or the "Predecessor"). The operations of the Partnership are
conducted through Plains Marketing, L.P. and All American Pipeline, L.P.
(collectively referred to as the "Operating Partnerships"). Plains All American
Inc., one of the Plains Midstream Subsidiaries, is the general partner ("General
Partner") of the Partnership and the Partnership. The Partnership is engaged in
interstate and intrastate crude oil pipeline transportation and crude oil
terminalling and storage activities and gathering and marketing activities. The
Partnership's operations are concentrated in California, Texas, Oklahoma,
Louisiana and the Gulf of Mexico.
The Partnership owns and operates a 1,233-mile seasonally heated, 30-inch,
common carrier crude oil pipeline extending from California to West Texas (the
"All American Pipeline") and a 45-mile, 16-inch, crude oil gathering system in
the San Joaquin Valley of California (the "SJV Gathering System"), both of
which the General Partner purchased from Wingfoot Ventures Seven, Inc.
("Wingfoot"), a wholly owned subsidiary of The Goodyear Tire & Rubber Company
("Goodyear") in July 1998 for approximately $400 million (the "Acquisition")
(See Note 2). The Partnership also owns and operates a two million barrel,
above-ground crude oil terminalling and storage facility in Cushing, Oklahoma,
(the "Cushing Terminal").
Initial Public Offering and Concurrent Transactions
On November 23, 1998, the Partnership completed an initial public offering
(the "IPO") of 13,085,000 common units representing limited partner interests
(the "Common Units") and received therefrom net proceeds of approximately $244.7
million. Concurrently with the closing of the IPO, certain transactions
described in the following paragraphs were consummated in connection with the
formation of the Partnership. Such transactions and the transactions which
occurred in conjunction with the IPO are referred to herein as the
"Transactions."
Certain of the Plains Midstream Subsidiaries were merged into Plains
Resources, which sold the assets of these subsidiaries to the Partnership in
exchange for $64.1 million and the assumption of $11.0 million of related
indebtedness. At the same time, the General Partner conveyed all of its interest
in the All American Pipeline and the SJV Gathering System, which it acquired in
July 1998 for approximately $400 million, to the Partnership in exchange for (i)
6,974,239 Common Units, 10,029,619 Subordinated Units and an aggregate 2%
general partner interest in the Partnership, (ii) the right to receive Incentive
Distributions as defined in the Partnership agreement; and (iii) the assumption
by the Partnership of $175 million of indebtedness incurred by the General
Partner in connection with the acquisition of the All American Pipeline and the
SJV Gathering System.
In addition to the $64.1 million paid to Plains Resources, the Partnership
distributed approximately $177.6 million to the General Partner and used
approximately $3 million of the remaining proceeds to pay expenses incurred in
connection with the Transactions. The General Partner used $121.0 million of the
cash distributed to it to retire the remaining indebtedness incurred in
connection with the acquisition of the All American Pipeline and the SJV
Gathering System and to pay other costs associated with the Transactions. The
balance, $56.6 million, was distributed to Plains Resources, which used the cash
to repay indebtedness and for other general corporate purposes.
In addition, concurrently with the closing of the IPO, the Partnership
entered into a $225 million bank credit agreement (the "Bank Credit
Agreement") that includes a $175 million term loan facility (the "Term Loan
Facility") and a $50 million revolving credit facility (the "Revolving Credit
Facility"). The Partnership may borrow up to $50 million under the Revolving
Credit Facility for acquisitions, capital improvements, working capital and
general business purposes. At closing, the Partnership had $175 million
outstanding under the Term Loan Facility, representing indebtedness assumed from
the General Partner.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 1998, of the Partnership and
the results of its operations, cash flows and changes in partners' equity for
the period from
F-7
November 23, 1998 to December 31, 1998. The combined financial statements of
the Predecessor include the accounts of the Plains Midstream Subsidiaries. All
significant intercompany transactions have been eliminated.
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 the Partnership, which typically occurs upon
receipt of the product by the Partnership. Terminalling and storage revenues are
recognized at the time service is performed. As a regulated interstate pipeline,
revenues for the transportation of crude oil on the All American Pipeline are
recognized based upon Federal Energy Regulatory Commission and the Public
Utilities Commission of the State of California filed tariff rates and the
related transported volumes. Tariff revenue is recognized at the time such
volume is delivered.
Cost of Sales and Operations
Cost of sales consists of the cost of crude oil and field and pipeline
operating 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. The Predecessor's cash management program resulted
in book overdraft balances which have been reclassified to current liabilities.
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.
Property and Equipment and Pipeline Linefill
Property and equipment is stated at cost and consists primarily of (i) crude
oil pipelines and pipeline facilities (primarily the All American Pipeline and
SJV Gathering System), (ii) crude oil terminal and storage facilities (primarily
the Cushing Terminal), and (iii) trucking equipment, injection stations and
other. Other property and equipment consists primarily of office furniture and
fixtures and computer equipment and software. Depreciation is computed using the
straight-line method over estimated useful lives as follows: (i) crude oil
pipelines - 40 years, (ii) crude oil pipeline facilities - 25 years, (iii) crude
oil terminal and storage facilities - 30 to 40 years, (iv) trucking equipment,
injection stations and other - 5 to 10 years and (v) 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 is 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
if forces a barrel out at another location. The Partnership owns approximately
5.0 million barrels of crude oil that is used to maintain the All American
Pipeline's 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.
F-8
The following is a summary of the components of property and equipment:
December 31,
--------------------------------
1998 1997
------------ -------------
(in thousands)
Crude oil pipelines $ 268,219 $ -
Crude oil pipeline facilities 70,870 -
Crude oil storage and terminal facilities 34,606 33,491
Trucking equipment, injection stations and other 5,140 2,798
--------- ----------
378,835 36,289
Less accumulated depreciation and amortization (799) (3,903)
--------- ----------
$ 378,036 $ 32,386
========= ==========
Impairment of Long-Lived Assets
Long-lived assets with recorded values that are not expected to be recovered
through future cash flows are written-down to estimated fair value in accordance
with Statement of Financial Accounting Standards No. 121. Fair value is
generally determined from estimated discounted future net cash flows.
Other Assets
Other assets consist of the following:
December 31,
-----------------------
1998 1997
-------- -------
(in thousands)
Debt issue costs $ 10,171 $ 232
Goodwill and other 1,134 2,096
------- ------
$ 11,305 $ 2,328
Accumulated amortization $ (495) $ (522)
------- ------
$ 10,810 $ 1,806
======= ======
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. The increase in debt issue costs is due to the IPO and the
acquisition of the All American Pipeline and the SJV Gathering System. 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 the
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 the operations of the Partnership
is included in the accompanying consolidated financial statements because, as a
partnership, it is not subject to Federal or state income tax and the tax effect
of it's 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 basis and his/her share of
the net assets reported in the consolidated financial statements. The
Partnership does not have access to information about each individual
Unitholder's tax attributes in the Partnership, and the aggregate tax bases
cannot be readily determined. Accordingly, management does not believe that, in
the Partnership's circumstances, the aggregate difference would be meaningful
information.
The Predecessor is included in the combined federal income tax return of
Plains Resources. Income taxes are calculated as if the Predecessor had filed a
return on a separate company basis utilizing a federal statutory rate of 35%.
Payables in lieu of deferred taxes represent deferred tax liabilities which are
recognized based on the temporary differences between the tax basis of the
Predecessor's assets and liabilities and the amounts reported in the financial
statements. These amounts were owed to Plains Resources. Current amounts payable
were also owed to Plains Resources and are included in due to affiliates in the
accompanying combined balance sheet of the Predecessor.
F-9
Hedging
The Partnership and Predecessor utilize various derivative instruments, for
purposes other than trading, to hedge their 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 ("NYMEX") and crude oil swap
contracts entered into with financial institutions. The Partnership also
utilizes interest rate swaps to manage the interest rate exposure on its 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, the Partnership 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 the Partnership's and Predecessor's Statements of Income
until the underlying hedged transaction occurs. The financial impacts of crude
oil hedge contracts are included in the Partnership's and Predecessor's
statements of income 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 accounts payable and accrued liabilities in
the accompanying 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 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.
Net income per unit
Basic and diluted net income per unit is determined by dividing net income,
after deducting the General Partner's 2% interest, by the weighted average
number of outstanding Common Units and Subordinated Units (a total of 30,088,858
units as of December 31, 1998). For periods prior to November 23, 1998, such
units are equal to the Common and Subordinated Units received by the General
Partner in exchange for assets contributed to the Partnership.
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 is effective for
fiscal years beginning after June 15, 1999. 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 it is, the type of hedge
transaction. For fair value hedge transactions in which the Partnership is
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 the Partnership is 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. The Partnership is required to adopt this
statement beginning in 2000. The Partnership has not yet determined the affect
that the adoption of SFAS 133 will have on its financial position or results of
operations
In November 1998, the Emerging Issues Task Force ("EITF") released Issue No.
98-10, "Accounting for Energy Trading and Risk Management Activities". EITF
98-10 deals with entities that enter into derivatives and other third-party
contracts for the purchase and sale of a commodity in which they normally do
business (for example, crude oil and natural gas). The EITF reached a consensus
that energy trading contracts should be measured at fair value determined as of
the balance sheet date with the gains and losses included in earnings and
separately disclosed in the financial statements or footnotes thereto. The EITF
acknowledged that determining whether or when an entity is involved in energy
trading activities is a matter of judgment that depends on the relevant facts
and circumstances. As such, certain factors or indicators have been identified
by the EITF which should be considered in evaluating whether an operation's
energy contracts are entered into for trading purposes. EITF 98-10 is
F-10
required to be applied to financial statements issued by the Partnership
beginning in 1999. The adoption of this consensus is not expected to have a
material impact on the Partnership's results of operations or financial
position.
Note 2--Acquisition
On July 30, 1998, the 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 Goodyear, for
approximately $400 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 following unaudited
pro forma information is presented to show the pro forma revenues and net income
had the acquisition been consummated on January 1, 1997.
January 1, Year
1998 to Ended
November 22, December 31,
1998 1997
----------- -----------
(in thousands)
Revenues $ 1,390,893 $ 1,744,840
=========== ===========
Net income (loss) $ 14,448 $ (17,039)
=========== ===========
Basic and diluted net income (loss)
per limited partner unit $ 0.83 $ (0.98)
=========== ===========
The pro forma net loss for the year ended December 31, 1997, includes a non-
cash impairment charge of $64.2 million related to the writedown of pipeline
assets and linefill by Wingfoot in connection with the sale of the Celeron
Companies by Goodyear to the Predecessor. Based on the Predecessor's purchase
price allocation to property and equipment and pipeline linefill, an impairment
charge would not have been required had the Predecessor actually acquired the
Celeron Companies effective January 1, 1997. Excluding this impairment charge,
the Predecessor's pro forma net income for 1997 would have been $23.4 million
($1.35 per basic and diluted limited partner unit).
The acquisition was accounted for utilizing the purchase method of
accounting and the purchase price was allocated in accordance with Accounting
Principles Board Opinion No. 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
--------
$ 400,164
========
Financing for the acquisition was provided through (i) a $325 million, limited
recourse bank facility and (ii) an approximate $114 million capital contribution
by Plains Resources. Actual borrowings at closing were $300 million.
Note 3 - Credit Facilities
Bank Credit Agreement. The Partnership has a $225 million Bank Credit
Agreement which consists of the $175 million Term Loan Facility and the $50
million Revolving Credit Facility. The $50 million Revolving Credit Facility is
used for capital improvements and working capital and general business purposes
and contains a $10 million sublimit for letters of credit issued for general
corporate purposes. The Bank Credit Agreement is collateralized by a lien on
substantially all of the assets of the Partnership.
The Term Loan Facility bears interest at the Partnership's option at either
(i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable
margin. The Partnership has two ten year interest rate swaps (subject to
cancellation by the counterparty after seven years) aggregating $175 million
notional principal amount which fix the LIBOR portion of the interest rate (not
including the applicable margin) at a weighted average rate of approximately
5.24%. Borrowings under the Revolving Credit Facility bear interest at the
Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve-
adjusted LIBOR plus an applicable margin. The Partnership incurs a commitment
fee on the unused portion of the Revolving Credit Facility and, with respect to
each issued letter of credit, an issuance fee.
F-11
At December 31, 1998, the Partnership had $175 million outstanding under the
Term Loan Facility, which amount represents indebtedness assumed from the
General Partner. The Term Loan Facility matures in seven years, 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
two years. All borrowings for working capital purposes outstanding under the
Revolving Credit Facility must be reduced to no more than $8 million for at
least 15 consecutive days during each fiscal year. At December 31, 1998, there
are no amounts outstanding under the Revolving Credit Facility.
Letter of Credit Facility. In connection with the IPO, the Partnership
entered into a $175 million letter of credit and borrowing facility with
BankBoston, N.A. ("BankBoston"), ING (U.S.) Capital Corporation ("ING
Baring") and certain other lenders (the "Letter of Credit Facility"), which
replaced the Predecessor's similar facility. The purpose of the Letter of Credit
Facility is to provide (i) standby letters of credit to support the purchase and
exchange of crude oil for resale and (ii) borrowings to finance crude oil
inventory which has been hedged against future price risk or has been designated
as working inventory. The Letter of Credit Facility is collateralized by a lien
on substantially all of the assets of the Partnership. 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
current assets and current liabilities of the Partnership, primarily crude oil
inventory and accounts receivable and accounts payable related to the purchase
and sale of crude oil. At December 31, 1998, the borrowing base under the Letter
of Credit Facility was approximately $175 million.
The Letter of Credit Facility has a $40 million sublimit for borrowings to
finance crude oil purchased in connection with operations at the Partnership's
crude oil terminal and storage facilities. All purchases of crude oil inventory
financed are required to be hedged against future price risk on terms acceptable
to the lenders. At December 31, 1998, approximately $9.8 million was outstanding
under the sublimit. The interest rate in effect at December 31, 1998 was 6.8%.
At December 31, 1997, approximately $18 million in borrowings was outstanding
under a similar sublimit under the Predecessor's credit facility.
Letters of credit under the Letter of Credit Facility are generally issued for
up to 70 day periods. Borrowings bear interest at the Partnership's option at
either (i) the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the
applicable margin. The Partnership incurs a commitment fee on the unused portion
of the borrowing sublimit under the Letter of Credit Facility and an issuance
fee for each letter of credit issued. The Letter of Credit Facility expires July
31, 2001.
At December 31, 1998 and 1997, there were outstanding letters of credit of
approximately $62 million and $38 million, respectively, issued under the Letter
of Credit Facility and the Predecessor's letter of credit facility,
respectively. To date, no amounts have been drawn on such letters of credit
issued by the Partnership or the Predecessor.
Both the Letter of Credit Facility and the Bank Credit Agreement contain a
prohibition on distributions on, or purchases or redemptions of, Units if any
Default or Event of Default (as defined) is continuing. In addition, both
facilities contain various covenants limiting the ability of the Partnership to
(i) incur indebtedness, (ii) grant certain liens, (iii) sell assets in excess of
certain limitations, (iv) engage in transactions with affiliates, (v) make
investments, (vi) enter into hedging contracts and (vii) enter into a merger,
consolidation or sale of its assets. In addition, the terms of the Letter of
Credit Facility and the Bank Credit Agreement require the Partnership to
maintain (i) a Current Ratio (as defined) of at least 1.0 to 1.0; (ii) a Debt
Coverage Ratio (as defined) which is not greater than 5.0 to 1.0; (iii) an
Interest Coverage Ratio (as defined) which is not less than 3.0 to 1.0; (iv) a
Fixed Charge Coverage Ratio (as defined) which is not less than 1.25 to 1.0; and
(v) a Debt to Capital Ratio (as defined) of not greater than .60 to 1.0. In both
the Letter of Credit Facility and the Bank Credit Agreement, a Change in Control
(as defined) of Plains Resources constitutes an Event of Default.
Note 4 - Partnership Capital and Distributions
Partner's capital consists of 20,059,239 Common Units representing a
65.3% limited partner interest, (a subsidiary of the General Partner owns
6,974,239 of such Common Units), 10,029,619 Subordinated Units owned by a
subsidiary of the General Partner representing a 32.7% limited partner interest
and a 2% general partner interest. In the aggregate, the General Partner's
interests represent an effective 57.4% ownership of the Partnership's equity.
The Partnership will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash is generally defined as all cash and cash equivalents of
the Partnership on hand at the end of each quarter less reserves established by
the 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
F-12
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), the General Partner will receive distributions
which are generally equal to 15%, then 25% and then 50% of the distributions of
Available Cash that exceed the MQD or Target Distribution Level. The Target
Distribution Levels are based on the amounts of Available Cash from the
Partnership's 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.
On February 12, 1999, the Partnership paid a cash distribution of $0.193
per unit on its outstanding Common Units and Subordinated Units. The $5.8
million distribution was paid to Unitholders of record at the close of business
on January 29, 1999. A distribution of approximately $118,000 was paid to the
General Partner. The distribution represented the MQD prorated for the 39-day
period from November 23, 1998, the closing of the IPO, through December 31,
1998.
Note 5 -- Major Customers and Concentration of Credit Risk
During the period from January 1, 1998 to November 22, 1998, Sempra Energy
Trading Corporation ("Sempra") and Koch Oil Company ("Koch") accounted for 31%
and 19%, respectively of the Plains Midstream Subsidiaries' total sales. During
the period from November 23, 1998 to December 31, 1998, Sempra and Exxon Company
USA accounted for 20% and 11%, respectively of the Partnership's sales. For 1997
and 1996, customers accounting for more than 10% of total sales are as follows:
1997 - Koch - 30%, Sempra - 12% and Basis Petroleum Inc. ("Basis"), formerly
Phibro Energy U.S.A., Inc. - 11%; 1996 - Koch - 16% and Basis - 11%. No other
customer accounted for as much as 10% of total sales during 1998, 1997 and 1996.
Financial instruments which potentially subject the Partnership to
concentrations of credit risk consist principally of trade receivables. The
Partnership's accounts receivable are primarily from purchasers and shippers of
crude oil. This industry concentration has the potential to impact the
Partnership's 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. The Partnership generally requires letters of credit for
receivables from customers which are not considered investment grade, unless the
credit risk can otherwise be reduced.
Note 6--Related Party Transactions
The Partnership does not directly employ any persons to manage or operate its
business. These functions are provided by employees of the General Partner and
Plains Resources. The General Partner does not receive a management fee or other
compensation in connection with its management of the Partnership. The
Partnership reimburses the 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 the
Partnership, and all other expenses necessary or appropriate to the conduct of
the business of, and allocable to the Partnership. The Partnership Agreement
provides that the General Partner will determine the expenses that are allocable
to the Partnership in any reasonable manner determined by the General Partner in
its sole discretion. Total costs reimbursed to the General Partner and Plains
Resources by the Partnership were approximately $0.5 million for the period from
November 23, 1998 to December 31, 1998. Such costs include, (i) allocated
personnel costs (such as salaries and employee benefits) of the personnel
providing such services, (ii) rent on office space allocated to the General
Partner in Plains Resources' offices in Houston, Texas and (iii) out-of-pocket
expenses related to the provision of such services.
In connection with the IPO, the Partnership and Plains Resources entered into
the Crude Oil Marketing Agreement which provides for the marketing by Plains
Marketing, L.P. of Plains Resources crude oil production for a fee of $0.20 per
barrel. The Partnership paid Plains Resources approximately $4.1 million for the
purchase of crude oil under such agreement for the period from November 23, 1998
to December 31, 1998, and recognized approximately $120,000 of profit for such
period.
The Predecessor marketed certain crude oil production of Plains Resources, its
subsidiaries and its royalty owners. The Predecessor paid approximately $83.4
million, $101.2 million and $100.5 million for the purchase of these products
for the period from January 1, 1998 to November 22, 1998, and for the years
ended December 31, 1997 and 1996, respectively. In management's opinion, such
purchases were made at prevailing market rates. The Predecessor did not
recognize a profit on the sale of the barrels purchased from Plains Resources.
Prior to the IPO, the Plains Midstream Subsidiaries were guarantors of
Plains Resources' $225 million revolving credit facility and $200 million 10
1/4% Senior Subordinated Notes due 2006. The agreements under which such debt
was issued contain
F-13
covenants which, among other things, restricted the Plains Midstream
Subsidiaries' ability to make certain loans and investments and restricted
additional borrowings by the Plains Midstream Subsidiaries.
Plains Resources allocated certain direct and indirect general and
administrative expenses to the Predecessor during the period from January 1,
1998 to November 22, 1998, and for the years ended December 31, 1997 and 1996.
Indirect costs were allocated based on the number of employees. The types of
indirect expenses allocated to the Predecessor during these periods 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. Management believes that the method used
to allocate expenses is reasonable.
Prior to the IPO, the Plains Midstream Subsidiaries funded the acquisition of
certain asset and inventory purchases through borrowings from Plains Resources.
In addition, the Plains Midstream Subsidiaries participated in a cash management
arrangement with Plains Resources covering the funding of daily cash
requirements and the investing of excess cash. Amounts due to Plains Resources
under the arrangements bore interest at a rate of 10 1/4%. The balance due to
Plains Resources as of December 31, 1997, was approximately $26.7 million,
including $0.3 million of cumulative federal and state income taxes payable
Amounts due to other subsidiaries of Plains Resources as of December 31, 1997
aggregated approximately $10.8 million.
Note 7 -- Financial Instruments
Derivatives
The Partnership utilizes derivative financial instruments, as defined in SFAS
No. 119, "Disclosure About Derivative Financial Instruments and Fair Value of
Financial Instruments," to hedge its exposure to price volatility on crude oil
and does not use such instruments for speculative trading purposes. These
arrangements expose the Partnership to credit risk (as to counterparties) and to
risk of adverse price movements in certain cases where the Partnership's
purchases are less than expected. In the event of non-performance of a
counterparty, the Partnership 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 the non-performance of
a counterparty, the Partnership enters into such contracts with counterparties
that are considered investment grade, periodically reviews the financial
condition of such counterparties and continually monitors the effectiveness of
derivative financial instruments in achieving the Partnership's objectives. In
view of the Partnership's criteria for selecting counterparties, its process for
monitoring the financial strength of these counterparties and its experience to
date in successfully completing these transactions, the Partnership believes
that the risk of incurring significant financial statement loss due to the non-
performance of counterparties to these transactions is minimal.
At December 31, 1998, the Partnership's hedging activities included crude oil
futures contracts maturing in 1999, covering approximately 3.3 million barrels
of crude oil. 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 the Partnerships hedged inventory
or anticipated purchases of crude oil. Net deferred losses from the
Partnership's hedging activities were approximately $1.8 million at December 31,
1998.
Fair Value of Financial Instruments
In accordance with the requirements of SFAS No. 107, "Disclosures About 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, as defined. 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 agreements are based on current termination
values or quoted market prices of comparable contracts.
F-14
The Partnership has two 10-year interest rate swaps (subject to cancellation
by the counterparty after seven years) aggregating a notional principal amount
of $175 million which fix the LIBOR portion of the interest rate (not including
the applicable margin) on the Term Loan Facility at a weighted average rate of
approximately 5.24%. The carrying amounts and fair values of the Partnership's
financial instruments are as follows:
December 31,
--------------------------
1998
--------------------------
Carrying Fair
Amount Value
------------ ------------
(in thousands)
Unrealized loss or interest rate swaps $ - $ (2,164)
Note 8 -- Commitments and Contingencies
The Partnership leases office space under leases accounted for as operating
leases. Rental expense amounted to $0.7 million and $0.1 million for the period
from January 1, 1998 to November 22, 1998, and the period from November 23, 1998
to December 31, 1998, respectively. Minimum rental payments under operating
leases are $3.0 million for 1999; $1.4 million annually for 2000 through 2002;
$1.3 million for 2003 and thereafter $2.9 million.
The Partnership incurred costs associated with leased land, rights-of-way,
permits and regulatory fees of $0.2 million and $0.1 million for the period from
January 1, 1998 to November 22, 1998, and the period from November 23, 1998 to
December 31, 1998, respectively. At December 31, 1998, minimum future payments,
net of sublease income, associated with these contracts are approximately $0.3
million for the following year. Generally these contracts extend beyond one year
but can be canceled at any time should they not be required for operations.
In order to receive electrical power service at certain remote locations,
the Partnership has entered into facilities contracts with several utility
companies. These facilities charges are calculated periodically based upon,
among other factors, actual electricity energy used. Minimum future payments for
these contracts at December 31, 1998, are approximately $0.8 million annually
for each of the next five years.
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. The
Partnership has submitted a closure plan to the Regional Water Quality Board
("RWQB"). At the request of the RWQB, groundwater monitoring wells have been
installed from which water samples will be analyzed semi-annually. No
hydrocarbon contamination was detected in initial analyses taken in January
1999. The RWQB approval of the Partnership's closure plan is not expected until
subsequent semi-annual analyses have been performed. If the Partnership's
closure plan is disapproved, a government mandated remediation of the spill
could require significant expenditures, currently estimated to be approximately
$350,000, provided however, no assurance can be given that the actual cost
thereof will not exceed such estimate. The Partnership does not believe the
ultimate resolution of this issue will have a material adverse affect on the
Partnership's consolidated financial position, results of operations or cash
flows.
Prior to being acquired by the Predecessor in 1996, the Partnership's
terminal at Ingleside Texas (the "Ingleside Terminal") experienced releases of
refined petroleum products into the soil and groundwater underlying the site due
to activities on the property. The Partnership has proposed a voluntary state-
administered remediation of the contamination on the property to determine
whether the contamination extends outside the property boundaries. If the
Partnership's plan is disapproved, a government mandated remediation of the
spill could require more significant expenditures, currently estimated to
approximate $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 the Partnership from Plains Resources. The Partnership does not
believe the ultimate resolution of this issue will have a material adverse
affect on the Partnership's consolidated financial position, results of
operations or cash flows.
The Partnership may experience future releases of crude oil into the
environment from its pipeline and storage operations, or discover releases that
were previously unidentified. While the Partnership maintains 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 the All American Pipeline, the SJV Gathering System,
the Cushing Terminal, the Ingleside Terminal or other Partnership assets may
substantially affect the Partnership's business.
In March 1999, the Partnership signed a definitive agreement to acquire
Scurlock Permian LLC and certain other pipeline assets (see Note 14).
F-15
The Partnership, in the ordinary course of business, is a defendant in
various legal proceedings in which its exposure, individually and in the
aggregate, is not considered material to the accompanying financial statements.
At December 31, 1998, the Partnership had approximately $0.9 million accrued for
its various environmental and litigation contingencies.
Note 9 -- Supplemental Disclosures of Cash Flow Information
In connection with the formation of the Partnership, certain investing and
financial activities occurred. Effective November 23, 1998, substantially all of
the assets and liabilities of the Predecessor were conveyed at historical cost
to the Partnership. Net assets assumed by the Operating Partnership are as
follows (in thousands):
Cash and cash equivalent $ 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 102,705
Due to affiliates 8,942
Bank debt 183,600
--------
Total liabilities assumed 295,247
--------
Net assets assumed by the Partnership $273,466
========
Interest paid totaled $0.1 million for the period from November 23, 1998 to
December 31, 1998, and $8.5 million, $4.5 million, and $3.6 million for the
period from January 1, 1998 to November 22, 1998 and the years ended
December 31, 1997 and 1996, respectively.
Note 10 -- Long-Term Incentive Plans
The General Partner adopted the Plains All American Inc. 1998 Long-Term
Incentive Plan (the "Long-Term Incentive Plan") for employees and directors of
the General Partner and its affiliates who perform services for the Partnership.
The Long-Term Incentive Plan consists of two components, a restricted unit plan
(the "Restricted Unit Plan") and a unit option plan (the "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 the 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.
Approximately 500,000 Restricted Units were granted upon consummation of the IPO
to employees of the General Partner at a weighted average grant date fair value
of $20.00 per Unit. The Compensation Committee may, in the future, determine to
make additional grants under such 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 the General Partner will
be eligible to vest prior to termination of the Subordination Period. There have
been no grants to nonemployee directors as of December 31, 1998.
If a grantee terminates employment or membership on the Board of Directors 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 the General Partner in the open market, Common Units already owned
by the General Partner, Common Units acquired by the General Partner directly
from the Partnership or any other person, or any combination of the foregoing.
The General Partner will be entitled to reimbursement by the Partnership for the
cost incurred in acquiring such Common Units. If the Partnership issues 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
intended to serve as a means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity appreciation in respect
of the Common Units. Therefore, no consideration will be payable by the plan
participants upon receipt of the Common Units, and the Partnership will receive
no remuneration for such Units.
F-16
Unit Option Plan. The Unit Option Plan currently permits the grant of options
("Unit Options") covering Common Units. No grants were initially made under
the Unit Option Plan. The Compensation Committee may, in the future, determine
to make grants under such plan to employees and directors containing such terms
as the Committee shall determine.
Unit Options will 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, the General Partner will acquire Common Units
in the open market at a price equal to the then-prevailing price on the
principal national securities exchange upon which the Common Units are then
traded, or directly from the partnership or any other person, or use Common
Units already owned by the General Partner, or any combination of the foregoing.
The General Partner will be entitled to reimbursement by the partnership for the
difference between the cost incurred by the General Partner in acquiring such
Common Units and the proceeds received by the General Partner from an optionee
at the time of exercise. Thus, the cost of the Unit Options will be borne by
the Partnership. If the Partnership issues new Common Units upon exercise of the
Unit Options, the total number of Common Units outstanding will increase, and
the General Partner will remit to the Partnership the proceeds it received from
the optionee upon exercise of the Unit Option to the Partnership.
The Unit Option Plan has been designed to furnish additional compensation to
employees and directors and to align their economic interests with those of
Common Unitholders.
Transaction Grant Agreements. In addition to the grants made under the
Restricted Unit Plan described above, the General Partner agreed to transfer
approximately 325,000 of its affiliates' Common Units at a weighted average
grant fair value of $20.00 per Unit to certain key employees of the General
Partner (the "Transaction Grants"). Generally, approximately 72,000 of such
Common Units will 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 MQD 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, such Common Units will vest at the time the
Common Unit Arrearages for such year has been paid. In addition, approximately
36,000 of such Common Units will 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 MQD on all outstanding Common Units and Subordinated
Units and the related distribution on the general partner interest. Any Common
Units remaining unvested shall vest upon, and in the same proportion as, the
conversion of Subordinated Units.
The Partnership will recognize compensation expense in the future for the
Unit Options and Restricted Units described above when vesting becomes probable.
In addition, although, the Partnership is not required to reimburse the General
Partner for the Transaction Grants, accounting pronouncements will require the
Partnership to record compensation expense for such Units and a corresponding
capital contribution from the General Partner when vesting becomes probable.
Note 11 -- Operating Segments
The Partnership's operations consist of two operating segments: (1)
Pipeline Operations - engages in the interstate and intrastate crude oil
pipeline transportation and related gathering and marketing activities; (2)
Marketing, Gathering, Terminalling and Storage Operations - engages in crude oil
terminalling, storage, gathering and marketing activities other than related to
Pipeline Operations. Prior to the July 1998 acquisition of the All American
Pipeline and SJV Gathering System, the Predecessor had only marketing,
gathering, terminalling and storage operations.
The accounting policies of the segments are the same as those
described in Note 1. The Partnership evaluates segment performance based on
gross margin, gross profit and income before income taxes and extraordinary
items.
F-17
The following summarizes segment revenues, gross margin, gross profit and
income before income taxes and extraordinary items.
Marketing
Gathering,
Terminalling
(In thousands) Pipeline & Storage Total
- --------------------------------------------------------------------------------
January 1, 1998 to November 22, 1998
(Predecessor)
Revenues:
External Customers(a) $221,305 $755,496 $ 976,801
Intersegment(b) 21,166 2,391 23,557
Other 603 (31) 572
-------- -------- ----------
Total revenues of reportable
segments $243,074 $757,856 $1,000,930
======== ======== ==========
Segment gross margin(c) $ 13,222 $ 17,759 $ 30,981
Segment gross profit(d) $ 12,394 $ 14,061 $ 26,455
Income before income taxes and
extraordinary income $ 2,152 $ 9,436 $ 11,588
Interest expense $ 7,787 $ 3,473 $ 11,260
Depreciation and amortization $ 3,058 $ 1,121 $ 4,179
Provision in lieu of income taxes $ 4,563 $ -- $ 4,563
Capital Expenditures $393,379 $ 4,677 $ 398,056
- --------------------------------------------------------------------------------
November 23, 1998 to December 31, 1998
Revenues:
External Customers(a) $ 56,118 $122,785 $ 178,903
Intersegment(b) 2,029 429 2,458
Other -- 12 12
-------- -------- ----------
Total revenues of reportable
segments $ 58,147 $123,226 $ 181,373
======== ======== ==========
Segment gross margin(c) $ 3,546 $ 3,953 $ 7,499
Segment gross profit(d) $ 3,329 $ 3,399 $ 6,728
Income before income taxes and
extraordinary income $ 1,035 $ 3,142 $ 4,177
Interest expense $ 1,321 $ 50 $ 1,371
Depreciation and amortization $ 973 $ 219 $ 1,192
Capital Expenditures $ 352 $ 2,535 $ 2,887
Total Assets $472,144 $138,064 $ 610,208
- --------------------------------------------------------------------------------
Combined Total For the Year Ended December 31, 1998
Revenues:
External Customers(a) $277,423 $878,281 $1,155,704
Intersegment(b) 23,195 2,820 26,015
Other 603 (19) 584
-------- -------- ----------
Total revenues of reportable
segments $301,221 $881,082 $1,182,303
======== ======== ==========
Segment gross margin(c) $ 16,768 $ 21,712 $ 38,480
Segment gross profit(d) $ 15,723 $ 17,460 $ 33,183
Income before income taxes and
extraordinary income $ 3,187 $ 12,578 $ 15,765
Interest expense $ 9,108 $ 3,523 $ 12,631
Depreciation and amortization $ 4,031 $ 1,340 $ 5,371
Provision in lieu of income taxes $ 4,563 $ -- $ 4,563
Capital Expenditures $393,731 $ 7,212 $ 400,943
Total Assets $472,144 $138,064 $ 610,208
- --------------------------------------------------------------------------------
(a) Differences between total segment revenues and consolidated revenues relate
to intersegment revenues.
(b) Intersegment sales and transfers were conducted on an arm's-length basis.
(c) Gross margin is calculated as revenues less cost of sales and operations.
(d) Gross profit is calculated as revenues less cost of sales and operations
and general and administrative expenses.
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Note 12 -- Income Taxes
As discussed in Note 1, the Predecessor's results are included in Plains
Resources' combined federal income tax return. The amounts presented below were
calculated as if the Predecessor filed a separate tax return.
Provision in lieu of income taxes of the Predecessor consists of the
following components:
January 1, Year Ended
1998 To December 31,
November 22, -----------------------------
1998 1997 1996
------------ -------------- ------------
(in thousands)
Federal
Current $ 455 $ 38 $ 1
Deferred 3,390 1,131 706
State
Current - 99 19
Deferred 718 - -
------- ------- ------
Total $ 4,563 $ 1,268 $ 726
======= ======= ======
Actual provision in lieu of income taxes differs from provision in lieu of
income taxes computed by applying the U.S. federal statutory corporate tax rate
of 35% to income before such provision as follows:
January 1, Year Ended
1998 To December 31,
November 22, -----------------------------
1998 1997 1996
------------ -------------- ------------
(in thousands)
Provision at statutory rate $ 4,056 $ 1,169 $ 682
State income tax, net of
benefit for federal deduction 467 65 12
Permanent differences 40 34 32
-------- -------- --------
Total $ 4,563 $ 1,268 $ 726
======== ======== ========
The Plains Midstream Subsidiaries' payable in lieu of deferred taxes at
December 31, 1997 results from differences in depreciation methods used for
financial purposes and for tax purposes.
Note 13 -- Combined Equity
The following is a reconciliation of the combined equity balance of the Plains
Midstream Subsidiaries (in thousands):
Balance at December 31, 1995 $ 2,613
Net income for the year 1,222
-------
Balance at December 31, 1996 3,835
Net income for the year 2,140
-------
Balance at December 31, 1997 5,975
Capital contribution in connection with the
acquisition of the Celeron Companies 113,700
Dividend to Plains Resources (3,557)
Net income for the period from
January 1, 1998 to November 22, 1998 7,025
-------
$123,143
=======
Note 14 -- Subsequent Events
On March 17, 1999, the Partnership signed a definitive agreement with
Marathon Ashland Petroleum LLC to acquire Scurlock Permian LLC and certain other
pipeline assets. The cash purchase price for the acquisition is approximately
$138 million, plus associated closing and financing costs. The purchase price is
subject to adjustment at closing for working capital on April 1, 1999, the
effective date of the acquisition. Closing of the transaction is subject to
regulatory review and approval,
F-19
consents from third parties, and customary due diligence. Subject to
satisfaction of the foregoing conditions, the transaction is expected to close
in the second quarter of 1999. The Partnership has received a financing
commitment from one of its existing lenders, which in addition to other
financial resources currently available to the Partnership, will provide the
funds necessary to complete the transaction.
Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland
Petroleum LLC, is engaged in crude oil transportation, trading and marketing,
operating in 14 states with more than 2,400 miles of active pipelines, numerous
storage terminals and a fleet of more than 225 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, Howard, Martin, Midland, Regan,
Upton and Irion Counties, Texas. The assets to be acquired also include
approximately one million barrels of crude oil used for working inventory. The
definitive agreement provides that if either party fails to perform its
obligations thereunder through no fault of the other party, such defaulting
party shall pay the nondefaulting party $7.5 million as liquidated damages.
In March 1999, the Partnership adopted a plan to reduce staff in its
pipeline operations and to relocate certain functions. The Partnership estimates
that it will incur a charge to first quarter earnings of approximately $400,000
in connection with such plan.
F-20