<PAGE>
As filed with the Securities and Exchange Commission on September 22, 1999
Registration No. 333-86907
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-------------------------
Amendment No. 1
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
-------------------------
PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of Registrant as specified in its charter)
-------------------------
Delaware 4861 76-0582150
(State or other (Primary Standard (I.R.S. Employer
jurisdiction Industrial Identification No.)
of incorporation or Classification Code
organization) Number)
-------------------------
500 Dallas
Houston, Texas 77002
(713) 654-1414
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
-------------------------
Michael R. Patterson
500 Dallas
Houston, Texas 77002
(713) 654-1414
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
-------------------------
Copies to:
Andrews & Kurth L.L.P. Baker & Botts, L.L.P.
600 Travis, Suite 4200 3000 One Shell Plaza
Houston, Texas 77002 910 Louisiana
(713) 220-4200 Houston, Texas 77002
Attn: David P. Oelman (713) 229-1234
Attn: Joshua Davidson
-------------------------
Approximate date of commencement of proposed sale to the public: As soon as
practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, please check the following box. [_]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [_]
-------------------------
CALCULATION OF REGISTRATION FEE
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<TABLE>
<CAPTION>
Proposed Maximum
Title of Each Class of Securities Aggregate Offering Amount of
to be Registered Price(1)(2) Registration Fee
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<S> <C> <C>
Common units representing limited partner
interests................................ $59,231,900 $16,467(3)
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</TABLE>
(1) Includes common units issuable upon exercise of the underwriters' over-
allotment option.
(2) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).
(3) Plains All American Pipeline previously paid a filing fee of $15,985 in
connection with our original filing. An additional fee of $482 was
submitted prior to the filing of this amendment.
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The Registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrant
shall file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until this Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
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<PAGE>
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+The information in this prospectus is not complete and may be changed. We may +
+not sell these securities until the registration statement filed with the +
+Securities and Exchange Commission is effective. This prospectus is not an +
+offer to sell these securities and it is not soliciting an offer to buy these +
+securities in any state where the offer or sale is not permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
SUBJECT TO COMPLETION, DATED SEPTEMBER 22, 1999
PROSPECTUS
[LOGO]
2,600,000 Common Units
Plains All American Pipeline, L.P.
Representing Limited Partner Interests
$ per Unit
--------
Plains All American Pipeline, L.P. is selling 2,600,000 common units. Plains
All American Pipeline is engaged in interstate and intrastate crude oil
transportation, terminalling and storage, as well as crude oil gathering and
marketing activities. The underwriters named in this prospectus may purchase up
to 390,000 additional common units.
Common units are entitled to receive distributions of operating cash of $0.45
per quarter, or $1.80 on an annualized basis, before any distributions are paid
on subordinated units. For the second quarter of 1999, we distributed $0.4625
on all of our outstanding common and subordinated units. Subordinated units
also represent limited partner interests in our partnership and are owned by a
subsidiary of our general partner. We expect that the priority of the common
units will continue until at least December 31, 2003.
Our common units are listed on the New York Stock Exchange under the symbol
"PAA." On September 20, 1999, the last reported sale price on the New York
Stock Exchange was $19.81 per unit.
--------
Investing in the common units involves risks that we describe in the "Risk
Factors" section beginning on page 17 of this prospectus.
These risks include the following:
. Cash distributions on the common units are not assured.
. The legal duties of our general partner to unitholders are limited.
. Our business is managed by our general partner. You will have limited
voting rights and limited ability to remove the general partner.
. Our revenues and profitability are dependent on the volume of domestic
crude oil production, particularly offshore California production, and the
volume of crude oil we terminal, store, gather and market.
. You may be required to pay taxes on income from us even if you receive no
cash distributions.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
--------
<TABLE>
<CAPTION>
Per Common Unit Total
--------------- ------------
<S> <C> <C>
Public Offering Price $ $
Underwriting Discount $ $
Proceeds to Plains All American Pipeline (before
expenses) $ $
</TABLE>
The underwriters are offering the common units subject to various conditions.
The underwriters expect to deliver the common units to purchasers on or about
, 1999.
--------
Salomon Smith Barney Goldman, Sachs & Co.
A.G. Edwards & Sons, Inc.
First Union Capital Markets Corp.
, 1999
<PAGE>
You should rely only on the information contained in this prospectus. We
have not authorized anyone to provide you with different information. We are
not making an offer of these securities in any state where the offer is not
permitted. You should not assume that the information provided by this
prospectus is accurate as of any date other than the date on the front of this
prospectus.
----------------
TABLE OF CONTENTS
<TABLE>
<S> <C>
GUIDE TO READING THIS PROSPECTUS........................................... iii
PROSPECTUS SUMMARY......................................................... 1
PLAINS ALL AMERICAN PIPELINE, L.P. ........................................ 1
Pipeline Transportation Contracts........................................ 2
Business Strategy........................................................ 2
Competitive Strengths.................................................... 3
Distribution History..................................................... 4
Our General Partner...................................................... 4
PARTNERSHIP STRUCTURE AND MANAGEMENT....................................... 5
THE OFFERING............................................................... 7
SUMMARY PRO FORMA FINANCIAL AND OPERATING DATA............................. 9
SUMMARY OF RISK FACTORS.................................................... 11
Risks Inherent in an Investment in Plains All American Pipeline.......... 11
Risks Inherent in Our Business........................................... 11
Tax Risks to Common Unitholders.......................................... 12
SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES............ 13
DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES....... 14
SUMMARY OF TAX CONSIDERATIONS.............................................. 15
RISK FACTORS............................................................... 17
Risks Inherent in an Investment in Plains All American Pipeline ......... 17
Risks Inherent in Our Business........................................... 18
Tax Risks to Common Unitholders.......................................... 23
USE OF PROCEEDS............................................................ 25
CAPITALIZATION............................................................. 26
CASH DISTRIBUTION POLICY................................................... 27
Quarterly Distributions of Available Cash................................ 27
Available Cash........................................................... 27
Operating Surplus and Capital Surplus.................................... 28
Distributions of Available Cash from Operating Surplus During the
Subordination Period.................................................... 28
Distributions of Available Cash from Operating Surplus After the
Subordination Period.................................................... 29
Subordination Period; Conversion of Subordinated Units................... 29
Incentive Distribution Rights............................................ 30
</TABLE>
<TABLE>
<S> <C>
Distributions from Capital Surplus...................................... 31
Adjustment of Minimum Quarterly Distribution and Target Distribution
Levels................................................................. 32
Distributions of Cash Upon Liquidation.................................. 33
MARKET PRICE OF AND DISTRIBUTIONS ON UNITS................................ 35
Market Information...................................................... 35
Holders................................................................. 35
Distribution History.................................................... 35
SELECTED PRO FORMA FINANCIAL AND OPERATING DATA........................... 36
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA.......................... 38
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS............................................................... 40
Overview................................................................ 40
Recent Developments..................................................... 41
Results of Operations................................................... 41
Capital Resources, Liquidity and Financial Condition.................... 47
Recent Accounting Pronouncements........................................ 51
Year 2000............................................................... 51
Quantitative and Qualitative Disclosures About Market Risks............. 53
BUSINESS.................................................................. 54
Market Overview......................................................... 54
Business Strategy....................................................... 55
Competitive Strengths................................................... 57
Crude Oil Pipeline Operations........................................... 58
All American Pipeline................................................. 59
SJV Gathering System.................................................. 62
West Texas Gathering System........................................... 62
Spraberry Pipeline System............................................. 63
Sabine Pass Pipeline System........................................... 63
Ferriday Pipeline System.............................................. 63
East Texas Pipeline System............................................ 64
Illinois Basin Pipeline System........................................ 64
Terminalling and Storage Activities and Gathering and Marketing
Activities............................................................. 64
Terminalling and Storage Activities................................... 64
Gathering and Marketing Activities.................................... 67
Customers............................................................... 69
Competition............................................................. 69
</TABLE>
(i)
<PAGE>
<TABLE>
<S> <C>
Regulation............................................................... 70
Pipeline Regulation.................................................... 70
Tariff Regulation...................................................... 71
Trucking Regulation.................................................... 72
Environmental Regulation................................................. 72
General................................................................ 72
Water.................................................................. 72
Air Emissions.......................................................... 73
Solid Waste............................................................ 73
Hazardous Substances................................................... 73
OSHA................................................................... 74
Endangered Species Act................................................. 74
Hazardous Materials Transportation Requirements........................ 74
Environmental Remediation................................................ 74
Title to Properties...................................................... 75
Employees................................................................ 76
Legal Proceedings........................................................ 76
MANAGEMENT................................................................. 77
The General Partner Manages Plains All American Pipeline................. 77
Directors and Executive Officers of the General Partner.................. 77
Reimbursement of Expenses of the General Partner and its Affiliates...... 79
Executive Compensation................................................... 79
Employment Agreement..................................................... 79
Long-Term Incentive Plan................................................. 80
Transaction Grant Agreements............................................. 81
Management Incentive Plan................................................ 81
Compensation of Directors................................................ 81
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............. 82
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................. 84
Rights of the General Partner............................................ 84
Relationship with Plains Resources....................................... 84
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES....................... 86
Conflicts of Interest.................................................... 86
Fiduciary Duties Owed to Unitholders by the General Partner are
Prescribed by Law and the Partnership Agreement......................... 89
DESCRIPTION OF THE COMMON UNITS............................................ 91
The Units................................................................ 91
Transfer Agent and Registrar............................................. 91
Duties................................................................. 91
Resignation or Removal................................................. 91
Transfer of Common Units................................................. 91
Class B Common Units..................................................... 92
DESCRIPTION OF THE SUBORDINATED UNITS...................................... 93
Conversion of Subordinated Units......................................... 93
Limited Voting Rights.................................................... 94
</TABLE>
<TABLE>
<S> <C>
Distributions upon Liquidation............................................ 94
THE PARTNERSHIP AGREEMENT................................................... 95
Organization and Duration................................................. 95
Purpose................................................................... 95
Power of Attorney......................................................... 95
Capital Contributions..................................................... 95
Limited Liability......................................................... 96
Issuance of Additional Securities......................................... 97
Amendment of the Partnership Agreement.................................... 97
Merger, Sale or Other Disposition of Assets............................... 99
Termination and Dissolution............................................... 100
Liquidation and Distribution of Proceeds.................................. 100
Withdrawal or Removal of the General Partner.............................. 100
Transfer of General Partner Interests and Incentive Distribution Rights... 102
Change of Management Provisions........................................... 102
Limited Call Right........................................................ 103
Meetings; Voting.......................................................... 103
Status as Limited Partner or Assignee..................................... 104
Non-citizen Assignees; Redemption......................................... 104
Indemnification........................................................... 104
Books and Reports......................................................... 105
Right to Inspect our Books and Records.................................... 105
Registration Rights....................................................... 106
UNITS ELIGIBLE FOR FUTURE SALE.............................................. 107
TAX CONSIDERATIONS.......................................................... 109
Legal Opinions and Advice................................................. 109
Partnership Status........................................................ 110
Limited Partner Status.................................................... 111
Tax Consequences of Unit Ownership........................................ 111
Tax Treatment of Operations............................................... 116
Disposition of Common Units............................................... 117
Uniformity of Units....................................................... 119
Tax-Exempt Organizations and Other Investors.............................. 120
Administrative Matters.................................................... 121
State, Local and Other Tax Considerations................................. 123
INVESTMENT IN PLAINS ALL AMERICAN PIPELINE BY EMPLOYEE BENEFIT PLANS........ 124
UNDERWRITING................................................................ 125
VALIDITY OF THE COMMON UNITS................................................ 127
EXPERTS..................................................................... 127
WHERE YOU CAN FIND MORE INFORMATION......................................... 128
FORWARD-LOOKING STATEMENTS.................................................. 128
INDEX TO FINANCIAL STATEMENTS............................................... F-1
APPENDIX A-GLOSSARY......................................................... A-1
</TABLE>
(ii)
<PAGE>
GUIDE TO READING THIS PROSPECTUS
The following information should help you understand some of the
conventions used in this prospectus.
. For ease of reference, a glossary of some of the terms used in this
prospectus is included as Appendix A to this prospectus.
. When we refer to our predecessor in this prospectus, we mean the business
and operations of the midstream subsidiaries of Plains Resources prior to
the initial public offering in November 1998. We also sometimes refer to
our predecessor as the Plains Midstream Subsidiaries.
. Unless otherwise indicated, the information set forth in this prospectus
assumes: (1) a public offering price of $19.81 per common unit and (2)
that the underwriters' over-allotment option has not been exercised.
. When we refer to pro forma results, we are generally referring to our
historical results adjusted for the impact of our acquisitions and our
initial public offering. When we refer to pro forma as adjusted results,
we are referring to a further adjustment to reflect this offering.
. When we refer to common units, unless otherwise indicated, we are
referring to all common units, including the Class B common units.
(iii)
<PAGE>
PROSPECTUS SUMMARY
The summary highlights information contained elsewhere in this prospectus.
It does not contain all of the information that you should consider before
investing in the common units. You should read the entire prospectus carefully,
including the "Risk Factors" section and the financial statements and the notes
to those statements.
PLAINS ALL AMERICAN PIPELINE, L.P.
We are a publicly traded Delaware limited partnership engaged in interstate
and intrastate crude oil transportation, terminalling and storage, as well as
crude oil gathering and marketing activities. We were formed in September 1998
to acquire and operate the midstream crude oil business and assets of Plains
Resources Inc. In the last year, we have grown through acquisitions and
internal development to become one of the largest terminal operators, gatherers
and marketers of crude oil in the United States. We transport, terminal, gather
and market an aggregate of approximately 850,000 barrels of crude oil per day.
The acquisitions we completed during 1999 complemented our existing asset base
and enabled us to reduce costs, increase revenues and increase our quarterly
distribution per unit in the second quarter of 1999 from $0.45 to $0.4625 per
unit.
Our operations are concentrated in California, Texas, Oklahoma, Louisiana
and the Gulf of Mexico and can be categorized into three primary business
activities:
. Crude Oil Pipeline Transportation. We own and operate the All American
Pipeline, a 1,233-mile seasonally heated, 30-inch, common carrier crude
oil pipeline that delivers crude oil to various locations within
California and to major trading locations in West Texas. We also own
several other pipeline systems including:
. the San Joaquin Valley Gathering System in California;
. the West Texas Gathering System, the Spraberry Pipeline System, and the
East Texas Pipeline System, which are all located in Texas;
. the Sabine Pass Pipeline System in southwest Louisiana and southeast
Texas;
. the Ferriday Pipeline System in eastern Louisiana and western
Mississippi; and
. the Illinois Basin Pipeline System in southern Illinois.
Our activities from pipeline operations generally consist of transporting
third-party volumes of crude oil for a tariff, as well as merchant
activities designed to capture location and quality price differentials.
. Terminalling and Storage Activities. We own and operate a state-of-the-
art, 3.1 million barrel, above-ground crude oil terminalling and storage
facility at Cushing, Oklahoma, the largest crude oil trading hub in the
United States and the designated delivery point for New York Mercantile
Exchange ("NYMEX") crude oil futures contracts. We also have an
additional 6.6 million barrels of terminalling and storage capacity in
our other facilities, including tankage associated with our pipeline and
gathering systems. Our terminalling and storage operations generate
revenue through a combination of storage and throughput fees. Our storage
facilities also complement our merchant activities.
. Gathering and Marketing Activities. We own or lease approximately 290
trucks, 320 tractor-trailers and 240 injection stations, which we use in
our gathering and marketing activities. Our gathering and marketing
operations include:
. the purchase of crude oil at the wellhead and the bulk purchase of
crude oil at pipeline and terminal facilities;
. the transportation of crude oil on trucks, barges or pipelines; and
. the subsequent resale or exchange of crude oil at various points along
the crude oil distribution chain.
1
<PAGE>
For the year ended December 31, 1998, our pro forma gross margin, EBITDA,
cash flow from operations and net income totaled $97.4 million, $74.1 million,
$52.5 million and $25.2 million, respectively. For the six months ended June
30, 1999, our pro forma gross margin, EBITDA, cash flow from operations and net
income totaled $65.8 million, $39.8 million, $29.1 million and $29.7 million,
respectively. On a pro forma basis, our pipeline operations accounted for
approximately 40% of our pro forma gross margin for the six-month period ended
June 30, 1999, while our terminalling and storage activities and gathering and
marketing activities accounted for approximately 60%. The pro forma gross
margin and net income amounts set forth above include a $9.5 million non-cash
inventory valuation charge for the year ended December 31, 1998 and a $9.5
million non-cash inventory valuation credit for the six months ended June 30,
1999.
Pipeline Transportation Contracts
Crude oil currently transported on the All American Pipeline and the SJV
Gathering System originates from fields offshore California and in the San
Joaquin Valley of California. We have long-term contracts to transport
production from the Santa Ynez field, operated by Exxon, and the Point Arguello
field, which we expect to be operated by a subsidiary of Plains Resources upon
receipt of regulatory approval. Both fields are located offshore and are
currently producing an aggregate of approximately 80,000 barrels of oil per
day. Exxon and Plains Resources, as well as Texaco and Oryx, 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. We also have an arrangement with Texaco to transport up to 40,000
barrels per day from the Midway Sunset Field and other onshore fields on our
SJV Gathering System to our interconnect with another company's pipeline that
transports oil to Los Angeles refiners. These arrangements extend through
October 2003. In West Texas, we have a contractual arrangement with Chevron USA
whereby Chevron has committed to transport its equity crude oil production from
fields connected to our West Texas Gathering System through July 2011.
Currently, Chevron's production that is subject to this commitment is
approximately 26,000 barrels per day.
Business Strategy
Our business strategy is to capitalize on the regional crude oil supply and
demand imbalances which exist in the continental United States by combining the
strategic location and unique capabilities of our transportation and
terminalling assets with our extensive marketing and distribution expertise to
generate sustainable earnings and cash flow for our unitholders.
We intend to execute our business strategy by:
. increasing and optimizing throughput on our various pipeline and
gathering assets;
. realizing cost efficiencies through operational improvements and
potential strategic alliances;
. utilizing our Cushing Terminal and our other assets to service the needs
of refiners and to profit from merchant activities that take advantage of
crude oil pricing and quality differentials; and
. pursuing strategic and accretive acquisitions of crude oil pipeline
assets, gathering systems and terminalling and storage facilities which
complement our existing asset base and distribution capabilities.
As part of our business strategy, we have taken the following actions:
. In May 1999, we completed an approximate 1.1 million barrel expansion
project at our Cushing Terminal for approximately $9.5 million that
increased our total capacity there by approximately 55%. This additional
capacity enhances our merchant capabilities and our ability to service
our terminalling and storage customers.
. On May 12, 1999, we completed the acquisition of Scurlock Permian LLC and
certain other pipeline assets from Marathon Ashland Petroleum LLC for
approximately $141 million. Scurlock is engaged
2
<PAGE>
in crude oil transportation, gathering and marketing, and has
approximately 2,300 miles of active pipelines, numerous storage terminals
and a fleet of more than 250 trucks. Scurlock's largest asset is an 800-
mile pipeline and gathering system located in the Spraberry Trend, which
is one of the largest producing areas in West Texas. The Spraberry
Pipeline System is located in close proximity to the West Texas Gathering
System, with which it interconnects at Midland, Texas, where third-party
transportation to the Cushing Interchange is available.
. On July 15, 1999, we completed the acquisition of the West Texas
Gathering System from Chevron Pipe Line Company for approximately $36
million. The assets acquired include approximately 450 miles of crude oil
transmission mainlines, approximately 340 miles of associated gathering
and lateral lines and approximately 2.9 million barrels of tankage
located along the system. The West Texas Gathering System is connected to
our All American Pipeline at Wink, Texas, and provides access to the
Midland, Texas crude oil interchange.
. On August 3, 1999, we received approval of our application to construct
an 8-inch pipeline underneath the Mississippi River at an estimated cost
of $1.5 million that will enable us to connect our Ferriday Pipeline
System in western Mississippi with the portion of our system located in
eastern Louisiana. When completed, this connection will provide us with
access to additional markets and enhance our ability to service our
pipeline customers and take advantage of additional high margin merchant
activities.
. On September 3, 1999, we completed the acquisition of a Louisiana crude
oil terminal facility and associated pipeline system from Marathon
Ashland Petroleum LLC for $1.5 million. The principal assets acquired
include approximately 300,000 barrels of crude oil storage and
terminalling capacity and a six-mile crude oil transmission system near
Venice, Louisiana. The current capacity of the terminal and pipeline
system is approximately 10,000 barrels of crude oil per day. The Venice
facility provides us with the opportunity to access additional sources of
supply in southern Louisiana.
. We have realized significant cost reductions. In each of the four
acquisitions that we have completed within the last fourteen months, we
immediately began to reorganize the operations and lower operating
expenses. Our efforts to lower operating costs do not end after our
initial post-acquisition restructuring, as evidenced by the further
restructuring of our All American Pipeline operations in March and
September of 1999.
Competitive Strengths
We believe we are well-positioned to successfully execute our business
strategy due to the following competitive strengths:
. Our pipeline assets are strategically located and have additional
capacity. Our primary crude oil pipeline transportation and gathering
assets are located in prolific oil producing regions and are connected,
directly or indirectly, with our terminalling and storage assets that
service major U.S. refinery and distribution markets where we have strong
business relationships. As a result, these assets are strategically
positioned to maximize the value of our crude oil by transporting it to
major trading locations and premium markets. In addition, most of our
major pipeline assets have existing incremental operating capacity that
allows us to add volumes at low incremental costs.
. Our Cushing Terminal is strategically located, operationally flexible and
readily expandable. The Cushing Terminal is the most modern terminalling
and storage facility at the Cushing Interchange, incorporating state-of-
the-art environmental safeguards and operational enhancements designed to
safely and efficiently terminal, store, blend and segregate large volumes
and multiple varieties of crude oil. The Cushing Terminal interconnects
with the Cushing Interchange's major inbound and outbound pipelines,
providing access to both foreign and domestic crude oil. The Cushing
Terminal can be readily expanded, should market conditions warrant, to
provide up to ten million barrels of tank capacity.
3
<PAGE>
. We possess specialized crude oil market knowledge. We believe our
business relationships with participants in all phases of the crude oil
distribution chain, from crude oil producers to refiners, as well as our
own industry expertise, provide us with a comprehensive understanding of
the U.S. crude oil markets.
. Our business activities are counter-cyclically balanced. We believe that
the counter-cyclical nature of our terminalling and storage activities
and our gathering and marketing activities, combined with the long-term
nature of our pipeline transportation contracts, will have a stabilizing
effect on our cash flow from operations.
. We have the financial flexibility to pursue expansion and acquisition
opportunities. We believe we have significant resources to finance
strategic expansion and acquisition opportunities, including additional
debt capacity and our ability to issue additional partnership units.
. We have an experienced management team. Our senior management team has an
average of more than 20 years industry experience, with an average of
over 15 years with us or our predecessors and affiliates.
Distribution History
We have made distributions of available cash to our partners for one partial
quarter and two full quarters since our initial public offering on November 23,
1998:
<TABLE>
<CAPTION>
Distribution
Declared Per Unit
--------------------
Common Subordinated
------- ------------
<S> <C> <C>
1999
Second quarter.................................... $0.4625 $0.4625
First quarter..................................... $0.45 $0.45
1998
Fourth quarter.................................... $0.193* $0.193*
</TABLE>
- --------
* Represents a partial quarterly distribution for the period from November
23, 1998, the date of our initial public offering, to December 31, 1998.
We paid the full minimum quarterly distribution of $0.45 per unit on all of
our common and subordinated units for the first quarter of 1999. In addition,
for the second quarter of 1999, we distributed $0.4625, representing $0.0125 in
excess of the minimum quarterly distribution on all of our outstanding common
and subordinated units. In accordance with the terms of our partnership
agreement, the general partner receives an increasing percentage of cash
distributed in excess of the minimum quarterly distribution of $0.45 per unit.
Accordingly, our general partner received 15% of the distributions in excess of
the minimum quarterly distribution for the second quarter of 1999.
Our General Partner
We are managed by our general partner, Plains All American Inc., which is a
wholly owned subsidiary of Plains Resources Inc. Plains Resources is an
independent energy company specializing in crude oil in both its upstream and
midstream segments, and is publicly traded on the American Stock Exchange under
the symbol "PLX." The midstream operations are conducted through Plains All
American Pipeline. We have a contractual arrangement with Plains Resources,
referred to as the Marketing Agreement, under which we purchase for resale at
market prices all of Plains Resources' equity crude oil production. We
currently receive a fee of $0.20 for every barrel we purchase from Plains
Resources. For the first six months of 1999, Plains Resources produced
approximately 18,600 barrels per day that were subject to the Marketing
Agreement, and we generated approximately $674,000 in revenue under the terms
of that agreement. Over 80% of Plains Resources' proved oil reserves are
located in California, where the company is the second largest independent oil
producer. Plains Resources' total year end proved reserves have grown from 13.7
million barrels of oil equivalent at January 1, 1992 to 134.7 million barrels
of oil equivalent at January 1, 1999, based on prevailing prices at those
dates.
4
<PAGE>
PARTNERSHIP STRUCTURE AND MANAGEMENT
Our operations are conducted through, and our operating assets are owned by,
our subsidiaries. We own our interests in our subsidiaries through three
operating partnerships, Plains Marketing, L.P., All American Pipeline, L.P. and
Plains Scurlock Permian, L.P.
The general partner has sole responsibility for conducting our business and
managing our operations and owns all of the incentive distribution rights. Some
of the senior executives who currently manage our business also manage and
operate the business of Plains Resources. The general partner does not receive
any management fee or other compensation in connection with its management of
our business, but it is reimbursed for all direct and indirect expenses
incurred on our behalf.
Our principal executive offices are located at 500 Dallas, Suite 700,
Houston, Texas 77002, and our phone number is (713) 654-1414.
The chart on the following page depicts the organization and ownership of
Plains All American Pipeline, the operating partnerships and the subsidiaries,
after giving effect to the offering. As is reflected in the chart, a subsidiary
of the general partner owns 6,974,239 common units and 10,029,619 subordinated
units, representing a 20.1% and 28.9% interest in the partnership and our
subsidiaries. In addition, our general partner owns 1,307,190 Class B common
units representing a 3.8% interest in the partnership and our subsidiaries. The
Class B common units are substantially identical to the common units and may be
converted into common units upon approval by a majority of the common units
voting at a meeting of unitholders. We used the approximately $25 million in
proceeds we received from the issuance of the Class B common units to fund a
portion of the consideration for the Scurlock acquisition. The percentages
reflected in the organization chart represent the approximate ownership
interest in Plains All American Pipeline, the operating partnerships and their
subsidiaries individually and not on a combined basis, unlike the other
presentations in this prospectus.
5
<PAGE>
[CHART DEPICTING STRUCTURE OF THE PLAINS ENTITIES APPEARS HERE]
6
<PAGE>
THE OFFERING
Common units offered..........
2,600,000 common units.
Units outstanding after this
offering...................... 23,966,429 common units, including 1,307,190
Class B common units, and 10,029,619
subordinated units, representing 69.1% and
28.9% limited partner interests in Plains All
American Pipeline.
Cash distributions............ We are required to distribute within 45 days
after the end of each quarter all of our cash
on hand at the end of each quarter, plus
working capital borrowings after the end of the
quarter, less reserves established by our
general partner in its discretion. We refer to
this cash as "available cash" and its meaning
is precisely defined in our partnership
agreement. We have also included this
definition in our glossary in Appendix A. The
amount of this cash may be greater than or less
than the minimum quarterly distribution.
Prior to making quarterly distributions, our
general partner may establish reserves for our
operations.
In general, cash distributions each quarter are
based on the following priorities:
. first, 98% to the common units and 2% to
the general partner, until each common
unit has received a minimum quarterly
distribution of $0.45 plus any arrearages
in the payment of the minimum quarterly
distribution from prior quarters; and
. second, 98% to the subordinated units and
2% to the general partner, until each
subordinated unit has received a minimum
quarterly distribution of $0.45.
If cash distributions exceed $0.45 per unit in
a quarter, the general partner will receive
incentive distributions.
Subordination period.......... The subordination period will end once we meet
the financial tests in the partnership
agreement, but it generally cannot end before
December 31, 2003.
When the subordination period ends, all
remaining subordinated units will convert into
common units on a one-for-one basis, and the
common units will no longer be entitled to
arrearages.
Early conversion of If the financial tests in the partnership
subordinated units............ agreement have been met for any quarter on or
after December 31, 2001, 25% of the
subordinated units will convert into common
units. If these tests have been met for any
quarter ending on or after December 31, 2002,
an additional 25% of the subordinated units
will convert into common units.
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The early conversion of the second 25% of the
subordinated units may not occur until at least
one year following the early conversion of the
first 25% of the subordinated units.
Issuance of additional In general, during the subordination period we
units......................... can issue up to 10,030,000 additional common
units without obtaining unitholder approval. We
can also issue an unlimited number of common
units for acquisitions which increase cash flow
from operations per unit on a pro forma basis.
Voting rights................. The general partner manages and operates Plains
All American Pipeline. Unlike the holders of
common stock in a corporation, you will have
only limited voting rights on matters affecting
our business. You will have no right to elect
our general partner on an annual or other
continuing basis. The general partner may not
be removed except pursuant to the vote of the
holders of at least 66 2/3% of the outstanding
units, including units owned by the general
partner and its affiliates.
Partnership termination....... Our existence will terminate on December 31,
2088, unless terminated sooner in accordance
with the terms of our partnership agreement.
NYSE listing.................. The common units are listed on the New York
Stock Exchange under the symbol "PAA."
8
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SUMMARY PRO FORMA FINANCIAL AND OPERATING DATA
The following unaudited Summary Pro Forma Financial and Operating Data are
derived from the historical financial statements of Plains All American
Pipeline; the Scurlock Permian businesses, formerly owned by Marathon Ashland
Petroleum; Wingfoot Ventures Seven, Inc., a wholly owned subsidiary of Goodyear
and the former owner of the All American Pipeline and the SJV Gathering System;
and our predecessor, the Plains Midstream Subsidiaries.
<TABLE>
<CAPTION>
Year Ended Six Months Ended
December 31, 1998 June 30, 1999
------------------------ ------------------------
Pro Pro Forma As Pro Pro Forma As
Forma (1) Adjusted (2) Forma (1) Adjusted (2)
---------- ------------ ---------- ------------
(in thousands, except per unit and barrel
amounts)
<S> <C> <C> <C> <C>
Income Statement Data:
Revenues................ $2,817,051 $2,817,051 $1,705,586 $1,705,586
Cost of sales and
operations............. 2,710,157 2,710,157 1,649,327 1,649,327
Inventory market
valuation charge
(credit)............... 9,499 9,499 (9,499) (9,499)
---------- ---------- ---------- ----------
Gross margin............ 97,395 97,395 65,758 65,758
---------- ---------- ---------- ----------
General and
administrative
expenses............... 34,183 34,183 16,791 16,791
Depreciation and
amortization........... 17,328 17,328 8,680 8,680
---------- ---------- ---------- ----------
Total expenses.......... 51,511 51,511 25,471 25,471
---------- ---------- ---------- ----------
Operating income........ 45,884 45,884 40,287 40,287
Interest expense........ 22,109 18,106(3) 10,911 9,062(3)
Other expense........... -- -- 410 410
Interest and other
income................. (1,435) (1,435) (768) (768)
---------- ---------- ---------- ----------
Pro forma net income.... $ 25,210 $ 29,213 $ 29,734 $ 31,583
========== ========== ========== ==========
Pro forma net income per
unit................... $ 0.79 $ 0.84 $ 0.93 $ 0.91
========== ========== ========== ==========
Balance Sheet Data (at
end of period):
Working capital......... $ 3,712
Total assets............ 1,006,786
Total long-term debt.... 240,314
Partners' capital....... 355,576
Other Data:
EBITDA(4)............... $ 74,146 $ 74,146 $ 39,826 $ 39,826
Maintenance capital
expenditures(5)........ 2,991 2,991 1,176 1,176
Operating Data:
Volumes (barrels per
day):
Lease gathering........ 282,400 282,400 316,900 316,900
Bulk purchases......... 212,100 212,100 189,300 189,300
Terminal
throughput(6)......... 79,800 79,800 79,200 79,200
Pipeline:
Tariff................ 152,300 152,300 138,900 138,900
Margin(7)............. 49,200 49,200 55,400 55,400
---------- ---------- ---------- ----------
Total pipeline....... 201,500 201,500 194,300 194,300
========== ========== ========== ==========
</TABLE>
9
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- --------
(1) Reflects the acquisition of the Scurlock Permian businesses, the
acquisition of the All American Pipeline and the SJV Gathering System, and
the initial public offering and the transactions whereby Plains All
American Pipeline became the successor to the business of our predecessor,
as if such transactions took place on January 1, 1998.
(2) In addition to the transactions described in footnote (1) above, reflects
the proceeds from this offering, including interest savings resulting from
the repayment of debt with these proceeds as if the offering took place on
January 1, 1998.
(3) Reflects the use of proceeds from this offering to repay a portion of our
borrowings under our $160 million Plains Scurlock credit facility. Our
ability to repay this debt is dependent upon obtaining the consent of the
lenders under our $225 million bank credit facility. If we are unable to
obtain this consent, we will use the proceeds to repay a portion of the
borrowings under our bank credit facility. Since the interest rate under
the Plains Scurlock credit facility is higher than the interest rate for
our bank credit facility borrowings, failure to obtain this consent would
result in pro forma as adjusted interest expense of approximately $18.7
million and $9.3 million, for the twelve month period ended December 31,
1998 and the six month period ended June 30, 1999, respectively.
(4) EBITDA means earnings before interest expense, income taxes, depreciation
and amortization. Our EBITDA calculation excludes a non-cash inventory
market valuation charge of approximately $9.5 million for the year ended
December 31, 1998, and a non-cash inventory market valuation credit of
approximately $9.5 million for the six months ended June 30, 1999. EBITDA
provides additional information for evaluating our 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 and is not intended to be used in lieu of
GAAP presentations of results of operations and cash provided by operating
activities. Our EBITDA may not be comparable to EBITDA of other entities as
other entities may not calculate EBITDA in the same manner as we do.
(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 our existing capacity, whether through
construction or acquisition, are not considered maintenance capital
expenditures. Repair and maintenance expenditures associated with existing
assets that do not extend the useful life or expand operating capacity are
charged to expense as incurred.
(6) Represents total crude oil barrels delivered from the Cushing Terminal and
the Ingleside Terminal.
(7) Represents crude oil deliveries on the All American Pipeline.
10
<PAGE>
SUMMARY OF RISK FACTORS
Risks Inherent in an Investment in Plains All American Pipeline
. You will have limited voting rights and will not control our general
partner.
. We may issue additional common units without your approval, which would
dilute existing unitholders' interests.
. Issuance of additional common units, including upon conversion of
subordinated units or exercise of the underwriters' over-allotment
option, will increase the risk that we will be unable to pay the full
minimum quarterly distribution on all common units.
. Cost reimbursements due to our general partner may be substantial and
could reduce our cash available for distribution.
. Our general partner has a limited call right that may require you to sell
your units at an undesirable time or price.
. You may not have limited liability in some circumstances.
Risks Inherent in Our Business
. Our profitability is dependent upon an adequate supply of crude oil from
fields located offshore and onshore California. Production from the
offshore fields has experienced substantial production declines since
1995.
. The success of our business strategy to increase and optimize throughput
on our pipeline and gathering assets is dependent upon our securing
additional supplies of crude oil.
. Our operations are dependent upon the demand for crude oil by refiners in
the Midwest and on the Gulf Coast. Any decrease in this demand could
adversely affect our business.
. We encounter 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. We also face intense competition in our
terminalling and storage activities and gathering and marketing
activities.
. The profitability of our gathering and marketing activities depends
primarily on the volumes of crude oil we purchase and gather.
. Any event that disrupts our anticipated physical supplies of crude oil
may expose us to risk of loss resulting from price changes.
. If we are unable to make acquisitions on economically and operationally
acceptable terms, our future financial performance will be limited to our
interest in our existing crude oil transportation, terminalling and
storage assets, and gathering and marketing activities.
. We are exposed to the credit risk of our customers in the ordinary course
of our gathering and marketing activities.
. Our operations are subject to federal and state environmental and safety
laws and regulations relating to environmental protection and operational
safety.
. Our pipeline systems are dependent upon their interconnections with other
crude oil pipelines to reach end markets.
. Our operations are subject to operational hazards and unforeseen
interruptions.
. Cash distributions are not guaranteed and may fluctuate with our
performance and the establishment of financial reserves.
. Our general partner's discretion in establishing financial reserves could
reduce your cash distributions.
11
<PAGE>
. Our indebtedness may limit our ability to borrow additional funds, make
distributions to unitholders or capitalize on business opportunities.
. Our operations could be adversely affected by data processing failures
after December 31, 1999. Failures could occur in our own systems as well
as the systems of our customers or suppliers.
Tax Risks to Common Unitholders
. The IRS could treat us as a corporation, which would substantially reduce
the cash available for distribution to unitholders.
. We have not requested an IRS ruling with respect to our tax treatment.
. You may be required to pay taxes on income from us even if you receive no
cash distributions.
. Tax gain or loss on disposition of common units could be different than
expected.
. Investors, other than individuals who are U.S. residents, may have
adverse tax consequences from owning units.
. We are registered as a tax shelter. This may increase the risk of an IRS
audit of us or a unitholder.
. We treat a purchaser of units as having the same tax benefits as the
seller. The IRS may challenge this treatment, which could adversely
affect the value of the units.
. You will likely be subject to state and local taxes as a result of an
investment in units.
12
<PAGE>
SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Plains All American Inc., our general partner, has a legal duty to manage us
in a manner beneficial to our unitholders. This legal duty originates in
statutes and judicial decisions and is commonly referred to as a "fiduciary"
duty. However, because Plains All American Inc. is a corporate subsidiary of
Plains Resources Inc., its officers and directors have fiduciary duties to
manage its business in a manner beneficial to those parties. As a result of
this relationship, conflicts of interest may arise in the future between us and
our unitholders, on the one hand, and the general partner and its shareholder
and affiliates, on the other hand.
The following situations, among others, could give rise to conflicts of
interest:
. our general partner determines the amount and timing of asset purchases
and sales, capital expenditures, borrowings, issuances of additional
securities and reserves, which can affect the amount of distributions to
unitholders;
. our general partner may take actions that have the effect of enabling it
or its affiliates to receive distributions on their own units or
incentive distribution rights, or hastening the expiration of the
subordination period or the conversion of their subordinated units into
common units; and
. some of the officers of our general partner, who provide services to us,
are also officers of Plains Resources Inc. and may devote time to the
businesses of Plains Resources Inc. Accordingly, competition for their
services may arise.
Our general partner is permitted to resolve conflicts of interest by
considering the interests of all the parties involved. Therefore, our general
partner can consider the interests of its affiliates, including Plains
Resources Inc., if a conflict of interest arises.
Our general partner has a conflicts committee, consisting of two independent
members of its board of directors, that reviews matters involving conflicts of
interest.
Our partnership agreement limits the liability and reduces the fiduciary
duties of our general partner to the unitholders. Our partnership agreement
also restricts the remedies available to unitholders for actions that might
otherwise constitute breaches of our general partner's fiduciary duty. By
purchasing a common unit, you are treated as having consented to various
actions contemplated in the partnership agreement and conflicts of interest
that might otherwise be considered a breach of fiduciary or other duties under
applicable state law.
13
<PAGE>
DISTRIBUTIONS AND PAYMENTS TO THE GENERAL PARTNER AND ITS AFFILIATES
The following table summarizes the distributions and payments to be made by
us to our general partner and its affiliates in connection with the ongoing
operation and the liquidation of Plains All American Pipeline. These
distributions and payments were determined by and among affiliated entities
and, consequently, are not the result of arm's length negotiations.
Operational Stage
Cash distributions of
available cash to our
general partner............. Cash distributions will generally be made 98%
to the unitholders, including to the general
partner and its affiliates as holders of common
units, including Class B common units, and
subordinated units, and 2% to the general
partner. In addition, if distributions exceed
the minimum quarterly distribution, our general
partner will be entitled to increasing
percentages of the distributions, up to 50% of
the distributions above the highest target
level. Our distribution to unitholders for the
second quarter of 1999 exceeded the minimum
quarterly distribution. In accordance with our
partnership agreement, amounts in excess of the
minimum quarterly distribution were distributed
15% to the general partner and 85% to the
limited partners.
For the six months ended June 30, 1999, our
general partner received distributions of
approximately $0.5 million on the combined 2%
general partner interest, approximately $0.1
million of incentive distributions, and
approximately $0.6 million on the Class B
common units, and a subsidiary of the general
partner received distributions of approximately
$15.5 million on its common and subordinated
units.
Payments to our general
partner and its
affiliates.................. Our general partner and its affiliates will not
receive any management fee or other
compensation for the management of Plains All
American Pipeline. Our general partner and its
affiliates will be reimbursed, however, for all
direct and indirect expenses incurred on our
behalf. For the six months ended June 30, 1999,
the general partner and its affiliates incurred
$13.3 million of direct and indirect expenses
on our behalf.
Withdrawal or removal of our
general partner............. If the general partner withdraws or is removed,
its general partner interest and its incentive
distribution rights will either be sold to the
new general partner for cash or converted into
common units, in each case for an amount equal
to the fair market value of those interests.
See "The Partnership Agreement -- Withdrawal or
Removal of the General Partner."
Liquidation Stage
Liquidation................... Upon our liquidation, the partners, including
our general partner, will be entitled to
receive liquidating distributions according to
their particular capital account balances.
14
<PAGE>
SUMMARY OF TAX CONSIDERATIONS
We have included below a summary of the primary tax considerations
associated with the ownership of common units. For a discussion of all of the
material tax considerations associated with the ownership of common units,
please see the discussion included under "Tax Considerations" which appears
later in this prospectus.
We are Treated as a Partnership for Tax Purposes
In the opinion of counsel, we have been and will be treated as a partnership
for federal income tax purposes. Accordingly, we will pay no federal income
taxes, and you will be required to report on your federal income tax return
your share of our income, gains, losses and deductions without regard to
distributions.
Allocations and Distributions are Based on Your Percentage Interest in Us
In general, our income and loss will be allocated to the general partner and
the unitholders for each taxable year according to their particular percentage
interests in Plains All American Pipeline. You will be required to take into
account, in determining your federal income tax liability, your share of our
taxable income for each of our taxable years ending with or within your taxable
year, even if cash distributions are not made to you. As a consequence, your
share of our taxable income, and possibly the income tax payable for that
income, may exceed the cash distributed to you.
The Ratio of Taxable Income to Distributions will be Less than Thirty Percent
We estimate that if you purchase common units in this offering and hold them
through December 31, 2002, you will be allocated an amount of federal taxable
income for that period which is less than 30% of the cash distributed to you
for that period. We anticipate that for taxable years beginning after December
31, 2002, the taxable income allocable to you will constitute a significantly
higher percentage of the cash distributed to you. However, we cannot assure you
that these estimates will be correct.
Losses are Only Available to Offset Our Future Income
In the case of taxpayers subject to the passive loss rules, generally
individuals and closely held corporations, our losses will only be available to
offset our future income and cannot be used to offset income from other
activities, including passive activities or investments, salary or other active
business income. Any losses unused by virtue of these rules can be deducted
when you dispose of all of your units in a fully taxable transaction with an
unrelated party.
We Have Made the Election to Permit Us to Adjust a Purchaser's Tax Basis in Our
Assets to Reflect the Purchase Price of a Purchaser's Common Units
We have made the election provided for by Section 754 of the Internal
Revenue Code. This election generally permits us to adjust a common unit
purchaser's tax basis in our assets to reflect the purchase price of his common
units and will generally give the purchaser income and deductions calculated by
reference to the portion of his purchase price attributable to each of our
assets. This election does not apply to a person who purchases common units
directly from us.
Disposition of Common Units Will Result in Gain or Loss
If you sell your common units you will recognize gain or loss equal to the
difference between the amount realized and your adjusted basis in those common
units. Thus, our distributions to you in excess of your share of our income
will, in effect, become taxable income if you sell your units at a price
greater than your adjusted tax basis, even if the price is less than your
original cost.
15
<PAGE>
Ownership of Common Units by Tax-Exempt Organizations and Other Investors
Raises Tax Issues
An investment in units by tax-exempt organizations, including individual
retirement accounts and other retirement plans, regulated investment companies
and foreign persons raises issues unique to them. Virtually all of our income
allocated to a unitholder which is a tax-exempt organization will be unrelated
business taxable income and will be taxable to the unitholder. Furthermore, no
significant amount of our gross income will be qualifying income for purposes
of determining whether a unitholder will qualify as a regulated investment
company. A unitholder who is a nonresident alien, foreign corporation or other
foreign person will be subject to withholding on his distributions and will be
required to file federal income tax returns and pay tax on his share of our
taxable income.
We Are Registered as a Tax Shelter with the IRS
We are registered as a tax shelter with the Secretary of the Treasury. Our
tax shelter registration number is 99061000009. Please see the discussion
appearing under the caption "Tax Considerations -- Administrative Matters;
Registration as a Tax Shelter" for a more complete discussion of the
consequences of this registration.
The issuance of a registration number by the Secretary of the Treasury does
not indicate that an investment in Plains All American Pipeline or the claimed
tax benefits have been reviewed, examined or approved by the IRS.
Other Tax Considerations
In addition to federal income taxes, you will likely be subject to other
taxes, including state and local income taxes, unincorporated business taxes
and estate, inheritance or intangible taxes that may be imposed by the various
jurisdictions in which you reside and in which we do business or own property.
You will likely be required to file state income tax returns and to pay taxes
in various states. You may also be subject to penalties for failure to comply
with these requirements.
The tax consequences of an investment in Plains All American Pipeline,
including federal income tax consequences, will depend in part on your own tax
circumstance. You should consult your own tax advisor to determine whether
specific personal tax consequences apply to you, as well as about the state,
local and foreign tax consequences of an investment in common units.
16
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RISK FACTORS
Limited partner interests are inherently different from capital stock of a
corporation, although many of the business risks to which we are subject are
similar to those that would be faced by a corporation engaged in a similar
business. You should carefully consider the following risk factors together
with all of the other information included in this prospectus in evaluating an
investment in the common units.
If any of the following risks were actually to occur, our business,
financial condition or results of operations could be materially adversely
affected. In that case, the trading price of our common units could decline and
you could lose all or part of your investment.
Risks Inherent in an Investment in Plains All American Pipeline
You will have limited voting rights and will not control our general
partner.
The general partner manages and operates our business. Unlike the holders of
common stock in a corporation, you will have only limited voting rights on
matters affecting our business. You will have no right to elect our general
partner on an annual or other continuing basis. Holders of units may not remove
the general partner without the vote of the holders of at least 66 2/3% of the
outstanding units, including units owned by the general partner and its
affiliates. The ownership of an aggregate of 53.9%, or 53.3% upon exercise of
the underwriters' over-allotment option in full, of the outstanding units by
the general partner and its affiliates gives the general partner the practical
ability to prevent its removal.
In addition, the partnership agreement contains provisions that may have the
effect of discouraging a person or group from attempting to remove our general
partner or otherwise changing our management. These provisions may diminish the
price at which the common units will trade under some circumstances. The
partnership agreement also contains provisions limiting the ability of
unitholders to call meetings or to acquire information about our operations, as
well as other provisions limiting the unitholders' ability to influence the
manner or direction of management. All matters, other than removal of a general
partner, requiring the approval of the unitholders during the subordination
period must first be proposed by our general partner. See "The Partnership
Agreement -- Withdrawal or Removal of the General Partner" and "-- Change of
Management Provisions."
We may issue additional common units without your approval, which would
dilute existing unitholders' interests.
During the subordination period, our general partner, without the approval
of the unitholders, may cause us to issue additional common units in a number
of circumstances. After the end of the subordination period, we may issue an
unlimited number of limited partner interests of any type without the approval
of the unitholders. Based on the circumstances of each case, the issuance of
additional common units or securities ranking senior to or on a parity with the
common units may dilute the value of the interests of the then-existing holders
of common units in our net assets, dilute the interests of unitholders in
distributions by us and, if issued during the subordination period, reduce the
support provided by the subordination feature of the subordinated units. Our
partnership agreement does not give the unitholders the right to approve our
issuance of equity securities ranking junior to the common units at any time.
Issuance of additional common units, including upon conversion of
subordinated units or exercise of the underwriters' over-allotment option, will
increase the risk that we will be unable to pay the full minimum quarterly
distribution on all common units.
Our ability to pay the full minimum quarterly distribution on all the common
units may be reduced by any increase in the number of outstanding common units,
including the increase resulting from this offering. Additional common units
would be issued as a result of:
. the conversion of subordinated units;
. the exercise of the underwriters' over-allotment option;
17
<PAGE>
. upon the conversion of the general partner interests and the incentive
distribution rights as a result of the withdrawal of our general partner;
or
. other future issuances of common units.
Any of these actions will increase the percentage of the aggregate minimum
quarterly distribution payable to the common unitholders and decrease the
percentage of the aggregate minimum quarterly distribution payable to the
subordinated unitholders, which will in turn have the effect of:
. reducing the amount of support provided by the subordination feature of
the subordinated units; and
. increasing the risk that we will be unable to pay the minimum quarterly
distribution in full on all the common units.
Cost reimbursements due to our general partner may be substantial and reduce
our cash available for distribution.
Prior to making any distribution on the common units, we will reimburse the
general partner and its affiliates, including officers and directors of the
general partner, for all expenses incurred on our behalf. The reimbursement of
expenses and the payment of fees could adversely affect our ability to make
distributions. The general partner has sole discretion to determine the amount
of these expenses. In addition, our general partner and its affiliates may
provide us services for which we will be charged reasonable fees as determined
by the general partner. For the six months ended June 30, 1999, the general
partner and its affiliates incurred $13.3 million of direct and indirect
expenses on our behalf.
Our general partner has a limited call right that may require you to sell
your units at an undesirable time or price.
If our general partner and its affiliates own 80% or more of the common
units, the general partner will have the right, which it may assign to any of
its affiliates, to acquire all, but not less than all, of the remaining common
units held by unaffiliated persons at a price generally equal to the then
current market price of the common units. As a result, you may be required to
sell your common units at a time when you may not desire to sell them or at a
price that is less than the price you would like to receive. You may also incur
a tax liability upon a sale of your units. See "The Partnership Agreement --
Limited Call Right."
You may not have limited liability in some circumstances.
The limitations on the liability of holders of limited partner interests for
the obligations of a limited partnership have not been clearly established in
some states. You could be held liable in some circumstances for our obligations
to the same extent as a general partner if a state or a court determined that:
. we had been conducting business in any state without compliance with the
applicable limited partnership statute; or
. the right or the exercise of the right by the unitholders as a group to
remove or replace our general partner, to approve some amendments to the
partnership agreement or to take other action under the partnership
agreement constituted participation in the "control" of our business.
In addition, under some circumstances a unitholder may be liable to us for the
amount of a distribution for a period of three years from the date of the
distribution. See "The Partnership Agreement -- Limited Liability" for a
discussion of the implications of the limitations on liability to a unitholder.
Risks Inherent in Our Business
Our profitability is dependent upon an adequate supply of crude oil from
fields located offshore and onshore California. Production from the offshore
fields has experienced substantial production declines since 1995.
A significant portion of our pro forma gross margin is derived from the
Santa Ynez and Point Arguello fields located offshore California. During the
first six months of 1999, approximately $15 million, or 23%, of
18
<PAGE>
our pro forma gross margin was attributable to the Santa Ynez field and
approximately $6 million, or 9%, was attributable to the Point Arguello field.
Although we have entered into contracts with the producers of most of the
production from these fields under which they have agreed to ship all of their
production from these fields on the All American Pipeline through August 2007,
they are not obligated to produce or ship any minimum volumes. Volumes received
from the Santa Ynez and Point Arguello fields have declined from 92,000 and
60,000 average daily barrels, respectively, in 1995 to 61,000 and 22,000
average daily barrels, respectively, for the first six months in 1999. We
expect that there will continue to be natural production declines from each of
these fields. In addition, any production disruption from these fields due to
production problems, transportation problems or other reasons would have a
material adverse effect on our business.
The success of our business strategy to increase and optimize throughput on
our pipeline and gathering assets is dependent upon our securing additional
supplies of crude oil.
Our operating results are dependent upon securing additional supplies of
crude oil from increased production by oil companies and aggressive lease
gathering efforts. The ability of producers to increase production is dependent
on the prevailing market price of oil, the exploration and production budgets
of the major and independent oil companies, the depletion rate of existing
reservoirs, the success of new wells drilled, environmental concerns,
regulatory initiatives and other matters beyond the control of the general
partner. There can be no assurance that production of crude oil will rise to
sufficient levels to cause an increase in the throughput on our pipeline and
gathering assets.
Our operations are dependent upon demand for crude oil by refiners in the
Midwest and on the Gulf Coast. Any decrease in this demand could adversely
affect our business.
Demand also depends on the ability and willingness of shippers having access
to our transportation assets to satisfy their demand by deliveries through
those assets, and any decrease in this demand could adversely affect our
business. Demand for crude oil is dependent upon the impact of future economic
conditions, fuel conservation measures, alternative fuel requirements,
governmental regulation or technological advances in fuel economy and energy
generation devices, all of which could reduce demand.
We encounter 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. We also face intense competition in our terminalling and storage
activities and gathering and marketing activities.
The Pacific Pipeline, a new pipeline connecting the San Joaquin Valley to
refinery markets in the Los Angeles Basin area, was completed and placed in
service in March 1999. We expect that certain volumes currently transported
east on the All American Pipeline may be redirected to Los Angeles through an
interconnect with the Pacific Pipeline.
The surplus of foreign oil in Midwest markets or the lack of foreign crude
oil imported into California could adversely impact our ability to transport
crude oil from California to West Texas on the All American Pipeline.
Our competitors include other crude oil pipelines, the major integrated oil
companies, their marketing affiliates and independent gatherers, brokers and
marketers of widely varying sizes, financial resources and experience. Some of
these competitors have capital resources many times greater than ours and
control substantially greater supplies of crude oil. See "Business --
Competition."
The profitability of our gathering and marketing activities depends
primarily on the volumes of crude oil we purchase and gather.
To maintain the volumes of crude oil we purchase, we must continue to
contract for new supplies of crude oil to offset volumes lost because of
natural declines in crude oil production from depleting wells or volumes lost
to competitors. Replacement of lost volumes of crude oil is particularly
difficult in an environment where
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production is low and competition to gather available production is intense.
Generally, because producers experience inconveniences in switching crude oil
purchasers, such as delays in receipt of proceeds while awaiting the
preparation of new division orders, producers typically do not change
purchasers on the basis of minor variations in price. Thus, we may experience
difficulty acquiring crude oil at the wellhead in areas where there are
existing relationships between producers and other gatherers and purchasers of
crude oil.
Sustained low crude oil prices could lead to a decline in drilling activity
and production levels or the shutting-in or abandonment of marginal wells. To
the extent that low crude oil prices result in lower volumes of crude oil
available for purchase at the wellhead, we may experience lower margins as
competition for available crude oil intensifies. In addition, a sustained
depression in crude oil prices could result in the bankruptcy of certain
producers. Although bankruptcy proceedings are not likely to terminate
production from oil wells, they may disrupt purchasing arrangements and have
other adverse consequences. Alternatively, sustained high crude oil prices can
limit the volume of crude oil we purchase if sufficient credit support for our
activities is unavailable.
Any event that disrupts our anticipated physical supplies of crude oil may
expose us to risk of loss resulting from price changes.
Generally, as we purchase crude oil, we establish a margin by selling crude
oil for physical delivery to third party users, such as independent refiners or
major oil companies, or by entering into a future delivery obligation with
respect to futures contracts on the NYMEX. Through these transactions, we seek
to maintain a position that is substantially balanced between crude oil
purchases, on the one hand, and sales or future delivery obligations, on the
other hand.
It is our policy not to acquire and hold crude oil, futures contracts or
derivative products for the purpose of speculating on price changes. Our price
risk management strategies cannot, however, eliminate all price risks. For
example, if the general partner inaccurately forecasts the shut-in of
production or other supply interruptions as the result of depressed oil prices,
mechanical interruptions, abrupt production declines or apportionment of
pipeline space on common carrier pipelines, we might be unable to meet our
supply commitments with the barrels purchased at the wellhead. We would be
forced to make purchases elsewhere in order to meet our commitments, and in the
event prices change adversely, our margins also may be adversely affected.
Moreover, we will be exposed to some risks that are not hedged, including
certain basis risks, such as the risk that price differentials between delivery
points, delivery periods or types of crude oil will change and price risks on
certain portions of our inventory. For accounting purposes, we may record
losses on a portion of the unhedged inventory due to market price declines,
although such losses would have no impact on cash flow as long as we are not
forced to liquidate such inventory.
If we are unable to make acquisitions on economically and operationally
acceptable terms, our future financial performance will be limited to our
interest in our existing crude oil transportation, terminalling and storage
assets, and gathering and marketing activities.
We cannot assure you that general economic or industry conditions will be
conducive to our acquisition strategy, that we will be able to identify and
acquire any assets or businesses on economically acceptable terms, that any
acquisitions will not be dilutive to earnings and distributions to unitholders
or that any additional debt incurred to finance an acquisition will not affect
our ability to make distributions to unitholders. We are subject to certain
covenants in our letter of credit facility and bank credit agreement that might
restrict our ability to incur indebtedness to finance acquisitions. We
routinely evaluate acquisition and expansion opportunities and have made
contact with several owners of potentially attractive assets and businesses.
However, we currently have no commitments for material acquisitions or
expansions at this time.
Our acquisition strategy involves numerous risks, including difficulties
inherent in the integration of operations and systems, the diversion of
management's attention from other business concerns and the potential loss of
key employees of acquired businesses. In addition, future acquisitions also may
involve the expenditure of significant funds. Depending upon the nature, size
and timing of future acquisitions, we may be required to
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<PAGE>
secure additional financing. There is no assurance that such additional
financing will be available to us on acceptable terms.
We are exposed to the credit risk of our customers in the ordinary course of
our gathering and marketing activities.
In those cases where we provide division order services for crude oil
purchased at the wellhead, we may be responsible for distribution of proceeds
to all parties. In other cases, we pay all of or a portion of the production
proceeds to an operator who distributes these proceeds to the various interest
owners. These arrangements expose us to operator credit risk. Therefore, we
must determine that operators have sufficient financial resources to make such
payments and distributions and to indemnify and defend us in case of a protest,
action or complaint. Even if our credit review and analysis mechanisms work
properly, there can be no assurance that we will not experience losses in
dealings with other parties.
Our operations are subject to federal and state environmental and safety
laws and regulations relating to environmental protection and operational
safety.
Our pipeline, gathering, storage and terminalling facilities operations are
subject to the risk of incurring substantial environmental and safety related
costs and liabilities. These costs and liabilities could arise under
increasingly strict environmental and safety laws, including regulations and
enforcement policies, or claims for damages to property or persons resulting
from our operations. If we were not able to recover such resulting costs
through insurance or increased tariffs and revenues, cash distributions to
unitholders could be adversely affected.
The transportation and storage of crude oil results in a risk that crude oil
and other hydrocarbons may be suddenly or gradually released into the
environment, potentially causing substantial expenditures for a response
action, significant government penalties, liability for natural resources
damages to government agencies, personal injury or property damages to private
parties and significant business interruption.
During 1997, the All American Pipeline experienced a leak in a segment of
its pipeline in California that resulted in an estimated 12,000 barrels of
crude oil being released into the soil. Immediate action was taken to repair
the pipeline leak, contain the spill and to recover the released crude oil. We
have expended approximately $400,000 to date in connection with this spill and
do not expect any additional expenditures to be material, although we can
provide no assurances in that regard.
Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and
groundwater underlying the site due to activities on the property. We are
undertaking a voluntary state-administered remediation of the contamination on
the property to determine the extent of the contamination. We expect that costs
associated with the remediation of the Ingleside Terminal will not exceed
$250,000, although we cannot provide you with any assurance in that regard.
Our pipeline systems are dependent upon their interconnections with other
crude oil pipelines to reach end markets.
Reduced throughput on these interconnecting pipelines as a result of
testing, line repair, reduced operating pressures or other causes could result
in reduced throughput on our pipeline systems which would adversely affect our
profitability.
Our operations are subject to operational hazards and unforeseen
interruptions.
Our operations are subject to operational hazards and unforseen
interruptions such as natural disasters, adverse weather, accidents or other
events beyond our control. A casualty occurrence might result in a loss of
equipment or life, as well as injury and extensive property or environmental
damage.
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Cash distributions are not guaranteed and may fluctuate with our
performance and the establishment of financial reserves.
Because distributions on the common units are dependent on the amount of
cash we generate, distributions may fluctuate based on our performance. We
cannot guarantee that the minimum quarterly distributions will be paid each
quarter. The actual amount of cash that is available to be distributed each
quarter will depend upon numerous factors, some of which are beyond our
control and the control of our general partner. Cash distributions are
dependent primarily on cash flow, including cash flow from financial reserves
and working capital borrowings, and not solely on profitability, which is
affected by non-cash items. Therefore, cash distributions might be made during
periods when we record losses and might not be made during periods when we
record profits.
Our general partner's discretion in establishing financial reserves could
reduce your cash distributions.
The partnership agreement gives our general partner broad discretion in
establishing financial reserves for the proper conduct of our business. These
reserves also will affect the amount of cash available for distribution. Our
general partner may establish reserves for distributions on the subordinated
units, but only if those reserves will not prevent us from distributing the
full minimum quarterly distribution, plus any arrearages, on the common units
for the following four quarters.
Our indebtedness may limit our ability to borrow additional funds, make
distributions to unitholders or capitalize on business opportunities.
Upon completion of the offering, we expect our total outstanding long-term
indebtedness to be approximately $278 million. Our leverage may:
. adversely affect our ability to finance future operations and capital
needs;
. limit our ability to pursue acquisitions and other business
opportunities; and
. make our results of operations more susceptible to adverse economic or
operating conditions.
Upon completion of this offering, we expect to have approximately $43 million
of aggregate unused borrowing capacity under our credit facilities. Future
borrowings, under our credit facilities or otherwise, could result in a
significant increase in our leverage.
Our payment of principal and interest on the indebtedness will reduce the
cash available for distribution on the units. We will be prohibited from
making cash distributions during an event of default under any of our
indebtedness. Various limitations in our indebtedness may reduce our ability
to incur additional indebtedness, to engage in some transactions and to
capitalize on business opportunities. Any subsequent refinancing of our
current indebtedness or any new indebtedness could have similar or greater
restrictions.
Our operations could be adversely affected by data processing failures
after December 31, 1999. Failures could occur in our own systems as well as
the systems of our customers or suppliers.
The approach of the year 2000 presents significant issues for many
financial information and operational computer systems. Many computer systems
in use today use two digits rather than four to identify a year, with the
result that these systems may be unable to distinguish the year 2000 from the
year 1900. Although many of our critical financial and production application
systems, hardware and software are now year 2000 compliant, some systems and
equipment are not converted. We do not expect the cost to make these
modifications and replacements to be material. However, if these modifications
and replacements are not made, are not made properly or are not completed in a
timely manner, the year 2000 issue may have a material adverse effect on our
business, results of operations and financial condition.
In addition, if any of our suppliers or customers do not successfully deal
with the year 2000 issue, we could experience delays that could result in
increased costs, lost revenues and customers and even claims for
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<PAGE>
damages. Customer problems with the year 2000 issue could also result in delays
in invoicing our customers or in our receiving payments from them that would
affect our liquidity. We are unable to predict the extent to which the year
2000 issue will have an effect on us. The severity of these possible problems
would depend on the nature of the problem and how quickly it could be corrected
or an alternative implemented, which is unknown at this time. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Year 2000."
Tax Risks to Common Unitholders
For a discussion of all of the expected material federal income tax
consequences of owning and disposing of common units, see "Tax Considerations."
The IRS could treat us as a corporation, which would substantially reduce
the cash available for distribution to unitholders.
The federal income tax benefit of an investment in the common units depends
largely on our being treated as a partnership for federal income tax purposes.
We have not requested, and do not plan to request, a ruling from the IRS on
this or any other matter affecting us. We have, however, received an opinion
from counsel that we have been and will be a partnership for federal income tax
purposes. Opinions of counsel are based on specified factual assumptions and
are not binding on the IRS or any court.
If we were classified as a corporation for federal income tax purposes, we
would pay federal income tax on our income at the corporate tax rate, which is
currently 35%. Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses, deductions or credits would flow
through to you. Because a tax would be imposed upon us as an entity, the cash
available for distribution to you would be substantially reduced. Treatment of
us as a corporation would result in a material reduction in the anticipated
cash flow and after-tax return to the unitholders, likely causing a substantial
reduction in the value of the common units.
We cannot assure you that the law will not change and cause us to be taxed
as a corporation for federal income tax purposes or otherwise subject us to
entity-level taxation. The partnership agreement provides that, if a law is
enacted or existing law is modified or interpreted in a manner that subjects us
to taxation as a corporation or otherwise subjects us to entity-level taxation
for federal, state or local income tax purposes, then distributions will be
decreased to reflect the impact of that law on us.
We have not requested an IRS ruling with respect to our tax treatment.
We have not requested a ruling from the IRS with respect to any matter
affecting us. The IRS may adopt positions that differ from the conclusions of
our counsel expressed in this prospectus or from the positions we take. It may
be necessary to resort to administrative or court proceedings to sustain some
or all of our counsel's conclusions or the positions we take. A court may not
concur with some or all of our conclusions. Any contest with the IRS may
materially and adversely impact the market for common units and the price at
which they trade. In addition, the costs of any contest with the IRS will be
borne directly or indirectly by some of the unitholders and the general
partner.
You may be required to pay taxes on income from us even if you receive no
cash distributions.
You will be required to pay any federal income taxes and, in some cases,
state and local income taxes on your allocable share of our income, whether or
not you receive cash distributions. We cannot assure you that you will receive
cash distributions equal to your allocable share of our taxable income or even
equal to the actual tax liability that results from your allocable share of our
income. Further, upon the sale of your units, you may incur a tax liability in
excess of the amount of cash you receive.
Tax gain or loss on disposition of common units could be different than
expected.
Upon the sale of common units, you will recognize gain or loss equal to the
difference between the amount realized and your tax basis in those common
units. Prior distributions in excess of the total net taxable
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<PAGE>
income you were allocated for a common unit, which decreased your tax basis in
that common unit, will, in effect, become taxable income if the common unit is
sold at a price greater than your tax basis in that common unit, even if the
price is less than your original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income.
Furthermore, should the IRS successfully contest some conventions we use, you
could recognize more gain on the sale of units than would be the case under
those conventions, without the benefit of decreased income in prior years.
Investors, other than individuals who are U.S. residents, may have adverse
tax consequences from owning units.
Investment in common units by tax-exempt entities, regulated investment
companies and foreign persons raises issues unique to them. For example,
virtually all of our income allocated to organizations exempt from federal
income tax, including individual retirement accounts and other retirement
plans, will be unrelated business taxable income and will be taxable to the
unitholder. Very little of our income will be qualifying income to a regulated
investment company. Distributions to foreign persons will be reduced by
withholding taxes, and foreign persons will be required to file federal income
tax returns and pay tax on their share of our taxable income.
We are registered as a tax shelter. This may increase the risk of an IRS
audit of us or a unitholder.
We are registered with the Secretary of the Treasury as a "tax shelter."
Our tax shelter registration number is 99061000009. The Secretary of the
Treasury has required that some types of entities, including some
partnerships, register as "tax shelters" in response to the perception that
they claim to generate tax benefits that the IRS may believe to be
unwarranted. We cannot assure unitholders that we will not be audited by the
IRS or that tax adjustments will not be made. Any unitholder owning less than
a 1% profits interest in us has very limited rights to participate in the
income tax audit process. Further, any adjustments in our tax returns will
lead to adjustments in the unitholders' tax returns and may lead to audits of
unitholders' tax returns and adjustments of items unrelated to us. Each
unitholder would bear the cost of any expense incurred in connection with an
examination of his personal tax return.
We treat a purchaser of units as having the same tax benefits as the
seller. The IRS may challenge this treatment, which could adversely affect the
value of the units.
Because we cannot match transferors and transferees of common units, we
have adopted depreciation and amortization conventions that do not conform
with all aspects of specified proposed and final Treasury regulations. A
successful IRS challenge to those conventions could adversely affect the
amount of tax benefits available to you. It also could affect the timing of
these tax benefits or the amount of gain from your sale of common units and
could have a negative impact on the value of the common units or result in
audit adjustments to your tax returns.
You will likely be subject to state and local taxes as a result of an
investment in units.
In addition to federal income taxes, you will likely be subject to other
taxes, including state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property. You will likely be
required to file state and local income tax returns and pay state and local
income taxes in some or all of the various jurisdictions in which we do
business or own property. Further, you may be subject to penalties for failure
to comply with those requirements. We own assets and do business in Alabama,
Arizona, Arkansas, California, Colorado, Florida, Illinois, Indiana, Kansas,
Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Montana, Nebraska, New
Mexico, North Dakota, Oklahoma, South Dakota, Texas, Utah and Wyoming. Of
these states, Florida, South Dakota, Texas and Wyoming do not currently impose
a personal income tax. It is your responsibility to file all United States
federal, state and local tax returns. Counsel has not rendered an opinion on
the state or local tax consequences of an investment in the common units.
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USE OF PROCEEDS
We estimate that the proceeds we will receive from this offering of common
units, together with a capital contribution from the general partner of
approximately $0.5 million to maintain its 2% general partner interest in our
partnership, will be approximately $49.7 million after deducting underwriting
discounts and commissions, but before deducting the other expenses associated
with the offering. We anticipate using these net proceeds to:
. repay approximately $49.0 million under the Plains Scurlock credit
facility, plus a $246,000 prepayment penalty; and
. pay approximately $500,000 in fees and expenses incurred in connection
with this offering.
The proceeds from any exercise of the underwriters' over-allotment option
will be used to further reduce any balance outstanding on the Plains Scurlock
credit facility.
At September 20, 1999, we had $126.6 million outstanding under the Plains
Scurlock credit facility, of which $90 million was borrowed in connection with
our purchase of Scurlock Permian from Marathon Ashland Petroleum on May 12,
1999, and $36.6 million was borrowed to finance the purchase of the West Texas
Gathering System on July 15, 1999. Borrowings under this facility bear interest
at LIBOR plus 3.0% (8.5% at September 20, 1999) and have a final maturity of
May 2004.
We are in the process of obtaining the consent of the lenders under our bank
credit facility to the repayment of the Plains Scurlock credit facility with
proceeds of this offering. If we fail to obtain this consent, we will apply the
net proceeds of this offering to repay amounts outstanding under our bank
credit facility. At September 20, 1999 we had approximately $200 million
outstanding under our bank credit facility of which $175 million represented
borrowings under our term loan and $25 million represented borrowings under the
revolving credit facility. Term loan borrowings under this facility currently
bear interest at LIBOR plus 1.75% and revolving credit borrowings currently
bear interest at LIBOR plus 1.50% (6.5% and 6.4%, respectively, at September
20, 1999) and have a final maturity of November 2004 for our term loan
borrowings and November 2002 for our revolving credit borrowings.
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CAPITALIZATION
The following table shows (1) our historical capitalization as of June 30,
1999 on an actual basis and (2) our pro forma capitalization as of June 30,
1999, adjusted to reflect the offering of the common units and the application
of the net proceeds we receive in the offering in the manner described under
"Use of Proceeds." This table is derived from, should be read in conjunction
with and is qualified in its entirety by reference to our historical and pro
forma financial statements and the accompanying notes included elsewhere in
this prospectus.
<TABLE>
<CAPTION>
As of June 30, 1999
-----------------------
Pro Forma
Actual As Adjusted
-------- -----------
(in thousands)
<S> <C> <C>
Cash and cash equivalents................... $ 12,133 $ 12,133
======== ========
Long-term debt:
Plains Scurlock credit facility........... $ 89,350(1) $ 40,314(1)(2)(3)
Bank credit agreement..................... 200,000 200,000(3)
-------- --------
Total long-term debt.................... 289,350 240,314
-------- --------
Partners' capital:
Common unitholders........................ 259,184 307,700
Class B common unitholders................ 25,295 25,295
Subordinated unitholders.................. 20,546 20,546
General partner........................... 1,515 2,035
-------- --------
Total partners' capital................. 306,540 355,576
-------- --------
Total capitalization.................... $595,890 $595,890
======== ========
</TABLE>
- --------
(1) Excludes approximately $36.6 million of indebtedness incurred in connection
with our purchase of the West Texas Gathering System on July 15, 1999.
(2) Reflects a penalty of approximately $246,000 associated with the prepayment
of the Plains Scurlock credit facility.
(3) Reflects the use of proceeds from this offering to repay a portion of our
borrowings under our Plains Scurlock credit facility. We are in the process
of obtaining the consent of the lenders under our bank credit facility to
this repayment. If we are unable to obtain this consent, we will use the
proceeds to reduce our borrowings under our bank credit facility to
approximately $151 million.
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CASH DISTRIBUTION POLICY
Quarterly Distributions of Available Cash
We will make distributions to our partners for each of our fiscal quarters
before liquidation in an amount equal to all available cash for that quarter.
Available cash is defined below in "-- available cash" and in our glossary. We
are required to make distributions of all available cash within approximately
45 days after the end of each quarter to holders of record on the applicable
record date.
For each quarter during the subordination period, to the extent there is
sufficient available cash, the holders of common units will have the right to
receive the minimum quarterly distribution of $0.45 per unit, plus any
arrearages on the common units, before any distribution is made to the holders
of subordinated units. This subordination feature enhances our ability to
distribute the minimum quarterly distribution on the common units during the
subordination period. There is no guarantee, however, that the minimum
quarterly distribution will be made on the common units.
If distributions from available cash on the common units for any quarter
during the subordination period are less than the minimum quarterly
distribution of $0.45 per common unit, holders of common units are entitled to
arrearages. Common unit arrearages will accrue and be paid in a future quarter
if there is available cash remaining after the minimum quarterly distribution
on the common units is paid for that quarter. Common units will not accrue
arrearages after the subordination period, and subordinated units will not
accrue any arrearages at any time.
The Class B common units are initially pari passu with common units with
respect to distributions, and after six months are convertible into common
units upon the request of the Class B unitholder and the approval of a majority
of the common units voting at a meeting of unitholders. If the approval of such
conversion by the common unitholders is not obtained within 120 days of such
request, each Class B common unit will be entitled to receive distributions, on
a per unit basis, equal to 110% of the amount of distributions paid on a common
unit, with such distribution right increasing to 115% if such approval is not
secured within 90 days after the end of the 120-day period. Except for the vote
to approve the conversion, Class B common units have the same voting rights as
the common units.
The holders of subordinated units will have the right to receive the minimum
quarterly distribution only after the common units have received the minimum
quarterly distribution plus any arrearages in payment of the minimum quarterly
distribution. Upon expiration of the subordination period, which will generally
not occur before December 31, 2003, the subordinated units will convert into
common units on a one-for-one basis. The subordinated units will then
participate pro rata with the other common units in distributions of available
cash. Under the circumstances described below, up to 50% of the subordinated
units may convert into common units before the expiration of the subordination
period.
Available Cash
Available cash is defined in the glossary and generally means, for any of
our fiscal quarters, all cash on hand at the end of the quarter less the amount
of cash reserves that is necessary or appropriate in the reasonable discretion
of the general partner to:
(1) provide for the proper conduct of our business;
(2) comply with applicable law, any of our debt instruments or other
agreements; or
(3) provide funds for distributions to unitholders and the general partner
for any one or more of the next four quarters,
plus working capital borrowings after the end of the quarter. Working capital
borrowings are generally borrowings made under our working capital facilities
or pursuant to another arrangement, which are used solely for working capital
purposes or to pay distributions to partners.
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Operating Surplus and Capital Surplus
Cash distributions will be characterized as distributions from either
operating surplus or capital surplus. This distinction affects the amounts
distributed to unitholders relative to the general partner, and also determines
whether holders of subordinated units receive any distributions.
Operating surplus is defined in the glossary and generally means:
(1) $29 million, plus all of our cash receipts from our operations
since the closing of our initial public offering, excluding cash from
borrowings other than working capital borrowings, sales of equity and debt
securities and sales of assets outside the ordinary course of business,
less
(2) payment of all of our operating expenses, debt service payments
(including reserves but not including payments required in connection with
the sale of assets or any refinancing with the proceeds of new indebtedness
or an equity offering), maintenance capital expenditures and reserves
established for future operations, in each case since the closing of our
initial public offering.
All available cash distributed from any source will be treated as
distributed from operating surplus until the sum of all available cash
distributed since we began operations equals the operating surplus as of the
end of the quarter before that distribution. This method of cash distribution
avoids the difficulty of trying to determine whether available cash is
distributed from operating surplus or capital surplus. Any excess of available
cash, irrespective of its source, will be treated as capital surplus, which
would represent a return of capital. Capital surplus is defined in the
glossary.
If capital surplus is distributed on a common unit issued in the offering in
an aggregate amount equal to the initial public offering price of the common
units ($20.00 per common unit), plus any arrearages in the payment of minimum
quarterly distributions on the common units, then the distinction between
operating surplus and capital surplus will cease. All subsequent distributions
of available cash will be made from operating surplus. See "-- Distributions
from Capital Surplus" below. We do not anticipate that there will be
significant distributions of capital surplus.
Adjusted operating surplus for any period generally means operating surplus
generated during that period, less:
(a) any net increase in working capital borrowings during that period;
and
(b) any net reduction in cash reserves for operating expenditures
during that period not relating to an operating expenditure made during
that period;
plus
(x) any net decrease in working capital borrowings during that period;
and
(y) any net increase in cash reserves for operating expenditures during
that period required by any debt instrument for the repayment of principal,
interest or premium.
Generally speaking, adjusted operating surplus is intended to reflect the cash
generated from operations during a particular period and therefore excludes net
increases in borrowings and net drawdowns of reserves of cash generated in
prior periods. Adjusted operating surplus is used in the test of whether
subordinated units can convert into common units.
Distributions of Available Cash from Operating Surplus During the Subordination
Period
Distributions of available cash from operating surplus for any quarter
during the subordination period will be made in the following manner:
. First, 98% to the common unitholders, pro rata, and 2% to the general
partner until we have distributed for each outstanding common unit an
amount equal to the minimum quarterly distribution for that quarter,
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. Second, 98% to the common unitholders, pro rata, and 2% to the general
partner until we have distributed for each outstanding common unit an
amount equal to any arrearages in payment of the minimum quarterly
distribution on the common units for any prior quarters during the
subordination period;
. Third, 98% to the subordinated unitholders, pro rata, and 2% to the
general partner until we have distributed for each subordinated unit an
amount equal to the minimum quarterly distribution for that quarter, and
. Thereafter, in the manner described in "-- Incentive Distributions
Rights" below.
Distributions of Available Cash from Operating Surplus After the Subordination
Period
Distributions of available cash from operating surplus for any quarter after
the subordination period will be made in the following manner:
. First, 98% to all unitholders, pro rata, and 2% to the general partner
until we have distributed for each outstanding unit an amount equal to
the minimum quarterly distribution for that quarter; and
. Thereafter, in the manner described in "-- Incentive Distribution Rights"
below.
Subordination Period; Conversion of Subordinated Units
The subordination period is defined in the glossary and will generally
extend until the first day of any quarter beginning after December 31, 2003
that each of the following three events occur.
(1) distributions of available cash from operating surplus on the common
units and the subordinated units equal or exceed the sum of the minimum
quarterly distributions on all of the outstanding common units and
subordinated units for each of the three non-overlapping four-quarter
periods immediately preceding that date;
(2) the adjusted operating surplus generated during each of the three
immediately preceding non-overlapping four-quarter periods equals or
exceeds the sum of the minimum quarterly distributions on all of the
outstanding common units and subordinated units during those periods on a
fully diluted basis and the related distribution on the 2% general partner
interest during those periods; and
(3) there are no arrearages, in payment of the minimum quarterly
distribution on the common units.
Before the end of the subordination period, a portion of the subordinated
units may convert into common units on a one-for-one basis on the first day
after the record date established for the distribution for any quarter ending
on or after:
(1) December 31, 2001 with respect to one-quarter of the subordinated
units; and
(2) December 31, 2002 with respect to one-quarter of the subordinated
units.
The conversions will occur if at the end of the applicable quarter each of
the following three events occurs:
(1) distributions of available cash from operating surplus on the common
units and the subordinated units equal or exceed the sum of the minimum
quarterly distributions on all of the outstanding common units and
subordinated units for each of the three non-overlapping four-quarter
periods immediately preceding that date;
(2) the adjusted operating surplus generated during each of the three
immediately preceding non-overlapping four-quarter periods equals or
exceeds the sum of the minimum quarterly distributions on all of the
outstanding common units and subordinated units during those periods on a
fully diluted basis and the related distribution on the 2% general partner
interest during those periods; and
29
<PAGE>
(3) there are no arrearages in payment of the minimum quarterly
distribution on the common units.
Upon expiration of the subordination period, all remaining subordinated
units will convert into common units on a one-for-one basis and will then
participate, pro rata, with the other common units in distributions of
available cash. In addition, if the general partner is removed as general
partner of Plains All American Pipeline under circumstances where cause does
not exist and units held by the general partner and its affiliates are not
voted in favor of that removal:
(1) the subordination period will end and all outstanding subordinated
units will immediately convert into common units on a one-for-one basis;
(2) any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
(3) the general partner will have the right to convert its general
partner interest and its incentive distribution rights into common units or
to receive cash in exchange for those interests.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing
percentage of quarterly distributions of available cash from operating surplus
after the minimum quarterly distribution and the target distribution levels
have been achieved. The general partner currently holds the incentive
distribution rights, but may transfer these rights separately from its general
partner interest, subject to restrictions in the partnership agreement.
If for any quarter:
(1) we have distributed available cash from operating surplus to the
common and subordinated unitholders in an amount equal to the minimum
quarterly distribution; and
(2) we have distributed available cash from operating surplus on
outstanding common units in an amount necessary to eliminate any cumulative
arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus
for that quarter among the unitholders and the general partner in the following
manner:
. First, 85% to all unitholders, pro rata, and 15% to the general partner,
until each unitholder has received a total of $0.495 per unit for that
quarter (the "first target distribution");
. Second, 75% to all unitholders and 25% to the general partner, until each
unitholder has received a total of $0.675 per unit for that quarter (the
"second target distribution"); and
. Thereafter, 50% to all unitholders, pro rata, and 50% to the general
partner.
In each case, the amount of the target distribution set forth above is
exclusive of any distributions to common unitholders to eliminate any
cumulative arrearages in payment of the minimum quarterly distribution on the
common units.
The following table illustrates the amount of available cash from operating
surplus that would be distributed on a yearly basis to the unitholders and the
general partner at each of the target distribution levels. This table is based
on the 23,966,429 common units, including the Class B common units, and the
10,029,619 subordinated units to be outstanding immediately after the offering
and assumes that there are no arrearages in payment of the minimum quarterly
distribution on the common units. The "Percentage" columns under "Yearly
Distributions" in the table below show the percentage interest of the
unitholders and the general partner in available cash from operating surplus
that would be distributed on a yearly basis between the
30
<PAGE>
indicated target distribution levels. The "Amount" columns under "Yearly
Distributions" in the table below show the cumulative amount that would be
distributed on a yearly basis to the unitholders and the general partner if
available cash from operating surplus equaled the indicated target distribution
level.
<TABLE>
<CAPTION>
Yearly Distributions
------------------------------------------------------
Unitholders General Partner Total
Quarterly --------------------- --------------------- ----------
Amount per Amount Amount Amount
Target Distribution Unit (millions) Percentage (millions) Percentage (millions)
------------------- ------------ ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Minimum Quarterly
Distribution........... $ 0.450 $ 61.2 98% $ 1.2 2% $ 62.4
First Target
Distribution........... 0.495 67.2 85% 2.4 15% 69.6
Second Target
Distribution........... 0.675 91.8 75% 10.5 25% 102.3
Thereafter.............. above 0.675 50% 50%
</TABLE>
The amounts and percentages shown under "Yearly Distributions--General Partner"
include the general partner's 2% general partner interest and the general
partner's incentive distribution rights. The amounts and percentages shown
under "Yearly Distributions--Unitholders" include amounts distributable on the
common units, Class B common units and the subordinated units. Assuming the
general partner and its affiliates continue to own 6,974,239 common units,
1,307,190 Class B common units and 10,029,619 subordinated units and other
persons own 15,685,000 common units, the general partner and its affiliates
will receive, in the aggregate, 53.9% of each amount shown as distributable to
unitholders, in addition to what the general partner receives on its general
partner interest.
Distributions from Capital Surplus
We will make distributions of available cash from capital surplus in the
following manner:
. First, 98% to all unitholders, pro rata, and 2% to the general partner
until we have distributed for each common unit, an amount of available
cash from capital surplus equal to the initial public offering price;
. Second, 98% to the common unitholders, pro rata, and 2% to the general
partner until we have distributed for each common unit, an amount of
available cash from capital surplus equal to any unpaid arrearages in
payment of the minimum quarterly distribution on the common units; and
. Thereafter, all distributions of available cash from capital surplus will
be distributed as if they were from operating surplus.
When a distribution is made from capital surplus, it is treated as if it
were a repayment of the unit price from the initial public offering. To reflect
repayment, we will adjust the minimum quarterly distribution and the target
distribution levels downward by multiplying each amount by a fraction. This
fraction is determined as follows:
. the numerator is the unrecovered initial public unit price of the common
units immediately after giving effect to the repayment; and
. the denominator is the unrecovered initial unit price of the common units
immediately before the repayment.
The unrecovered initial unit price is generally the initial public offering
price per unit less any distributions from capital surplus.
This adjustment to the minimum quarterly distribution may make it more
likely that subordinated units will be converted into common units, whether
upon the termination of the subordination period or the early conversion of
some subordinated units. This adjustment may also accelerate the dates at which
these conversions occur.
31
<PAGE>
A "payback" of the initial unit price occurs when the unrecovered initial
unit price of the common units is zero. At that time, the minimum quarterly
distribution and the target distribution levels each will have been reduced to
zero. All distributions of available cash from all sources after that time will
be treated as if they were from operating surplus. Because the minimum
quarterly distribution and the target distribution levels will have been
reduced to zero, the general partner, in its capacity as holder of the
incentive distribution rights, will then be entitled to receive 48% of all
distributions of available cash. This is in addition to any distributions to
which it may be entitled as a holder of units or its general partner interest.
Distributions from capital surplus will not reduce the minimum quarterly
distribution or target distribution levels for the quarter in which they are
distributed. We do not anticipate that there will be significant distributions
from capital surplus.
Adjustment of Minimum Quarterly Distribution and Target Distribution Levels
In addition to adjustments made upon a distribution of available cash from
capital surplus, we will adjust the following proportionately upward or
downward, as appropriate, if any combination or subdivision of units should
occur:
(1) the minimum quarterly distribution;
(2) the target distribution levels;
(3) the unrecovered initial unit price;
(4) the number of additional common units issuable during the
subordination period without a unitholder vote;
(5) the number of common units issuable upon conversion of the
subordinated units; and
(6) other amounts calculated on a per unit basis.
For example, if a two-for-one split of the common units should occur, the
minimum quarterly distribution, the target distribution levels and the
unrecovered initial unit price would each be reduced to 50% of its initial
level. We will not make any adjustment by reason of the issuance of additional
units for cash or property.
We may also adjust the minimum quarterly distribution and target
distribution levels if legislation is enacted or if existing law is modified or
interpreted in a manner that causes us or the subsidiaries to become taxable as
corporations or otherwise subject to taxation as entities for federal, state or
local income tax purposes. In this event, the minimum quarterly distribution
and target distribution levels for each quarter after that time would be
reduced to amounts equal to the product of:
(1)the minimum quarterly distribution and each of the target distribution
levels; multiplied by
(2)one minus the sum of:
(x) the highest marginal federal corporate income tax rate which could
apply; plus
(y)any increase in the effective overall state and local income tax rate
that would have been applicable to us or the subsidiaries in the
preceding calendar year as a result of the new imposition of the
entity level tax, after taking into account the benefit of any
deduction allowable for federal income tax purposes for the payment
of state and local income taxes, but only to the extent of the
increase in rates resulting from that legislation or interpretation.
For example, assuming we are not previously subject to state and local
income tax, if we were to become taxable as an entity for federal income tax
purposes and we became subject to a maximum marginal federal, and effective
state and local, income tax rate of 38%, then the minimum quarterly
distribution and the target distribution levels would each be reduced to 62% of
the amount thereof immediately before the adjustment.
32
<PAGE>
Distributions of Cash Upon Liquidation
Following the beginning of our dissolution and during the process of
selling all our assets, we will sell or otherwise dispose of assets and the
partners' capital account balances will be adjusted to reflect any resulting
gain or loss. Our dissolution and the process of selling all of our assets is
referred to as "liquidation." The proceeds of liquidation will first be
applied to the payment of our creditors in the order of priority provided in
the partnership agreement and by law. After that, we will distribute the
proceeds to the unitholders and the general partner in accordance with their
capital account balances, as so adjusted.
Partners are entitled to liquidating distributions in accordance with
capital account balances. The allocations of gains and losses upon liquidation
are intended, to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding subordinated
units upon our liquidation, to the extent required to permit common
unitholders to receive their unrecovered unit price plus any unpaid arrearages
in payment of the minimum quarterly distribution on the common units. Thus,
net losses recognized upon our liquidation will be allocated to the holders of
the subordinated units to the extent of their capital account balances before
any loss is allocated to the holders of the common units. Also, net gains
recognized upon liquidation will be allocated first to restore negative
balances in the capital accounts of the general partner and any unitholders
and then to the common unitholders until their capital account balances equal
their unrecovered initial unit price plus unpaid arrearages in payment of the
minimum quarterly distribution of the common units. However, we cannot assure
you that there will be sufficient gain upon our liquidation to enable the
holders of common units to fully recover all of these amounts, even though
there may be cash available for distribution to the holders of subordinated
units. Any further net gain as recognized upon liquidation will be allocated
in a manner that takes into account the incentive distribution rights of the
general partner.
The manner of the adjustment is as provided in the partnership agreement.
If our liquidation occurs before the end of the subordination period, we will
allocate any gain, or unrealized gain attributable to assets distributed in
kind, to the partners in the following manner:
. First, to the general partner and the holders of units who have negative
balances in their capital accounts to the extent of and in proportion to
those negative balances;
. Second, 98% to the common unitholders, pro rata, and 2% to the general
partner until the capital account for each common unit is equal to the
sum of:
(1) the unrecovered initial unit price for that common unit; plus
(2) the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs; plus
(3) any unpaid arrearages in payment of the minimum quarterly
distribution on that common unit;
. Third, 98% to the subordinated unitholders, pro rata, and 2% to the
general partner until the capital account for each subordinated unit is
equal to the sum of:
(1) the unrecovered initial unit price on that subordinated unit; and
(2) the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs;
. Fourth, 85% to all unitholders, pro rata, and 15% to the general partner
until there has been allocated under this paragraph an amount per unit
equal to:
(1) the sum of the excess of the first target distribution per unit
over the minimum quarterly distribution per unit for each quarter of our
existence; less
(2) the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the minimum quarterly distribution
per unit that was distributed 85% to the unitholders, pro rata, and 15% to
the general partner for each quarter of our existence;
33
<PAGE>
. Fifth, 75% to all unitholders, pro rata, and 25% to the general partner,
until there has been allocated under this paragraph an amount per unit
equal to:
(1) the sum of the excess of the second target distribution per unit
over the first target distribution per unit for each quarter of our
existence; less
(2) the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the first target distribution per
unit that was distributed 75% to the unitholders, pro rata, and 25% to the
general partner for each quarter of our existence;
. Thereafter, 50% to all unitholders, pro rata, and 50% to the general
partner.
If the liquidation occurs after the end of the subordination period, the
distinction between common units and subordinated units will disappear, so that
clause (3) of the second priority above and all of the third priority above
will no longer be applicable.
Upon our liquidation, we will generally allocate any loss to the general
partner and the unitholders in the following manner:
. First, 98% to holders of subordinated units in proportion to the positive
balances in their capital accounts and 2% to the general partner until
the capital accounts of the holders of the subordinated units have been
reduced to zero;
. Second, 98% to the holders of common units in proportion to the positive
balances in their capital accounts and 2% to the general partner until
the capital accounts of the common unitholders have been reduced to zero;
and
. Thereafter, 100% to the general partner.
If the liquidation occurs after the end of the subordination period, the
distinction between common units and subordinated units will disappear, so that
all of the first priority above will no longer be applicable.
In addition, we will make interim adjustments to capital accounts at the
time we issue additional interests in our partnership or make distributions of
property. These adjustments will be based on the fair market value of the
interests or the property distributed. We will allocate any gain or loss
resulting from the adjustments to the unitholders and the general partner in
the same manner as gain or loss is allocated upon liquidation. In the event
that positive interim adjustments are made to the capital accounts, any later
negative adjustments to the capital accounts resulting from the issuance of
additional units, our distributions of property or upon our liquidation, will
be allocated in a manner which results, to the extent possible, in the capital
account balances of the general partner equaling the amount which would have
been the general partner's capital account balances if no earlier positive
adjustments to the capital accounts have been made.
34
<PAGE>
MARKET PRICE OF AND DISTRIBUTIONS ON UNITS
Market Information
The common units, excluding the Class B common units, are listed on the NYSE
under the symbol "PAA." On September 20, 1999, the last reported per unit sales
price of the common units on the NYSE was $19.81. The following table sets
forth the high and low sales prices for the common units as reported on the
NYSE and the cash distributions declared per common unit for the periods
indicated.
<TABLE>
<CAPTION>
Distribution
Price Range Declared Per Unit
----------------- -----------------------
Common Subordinated
High Low Unit Unit
-------- -------- ------- ------------
<S> <C> <C> <C> <C>
1999
Third Quarter(1)................... $20.00 $18.375
Second Quarter..................... $19.3125 $16.3125 $0.4625 $0.4625
First Quarter...................... $19.00 $15.875 $0.45 $0.45
1998
Fourth Quarter..................... $20.125 $16.25 $ 0.193(2) $ 0.193(2)
</TABLE>
- --------
(1) Through September 20, 1999.
(2) Represents a partial quarterly distribution for the period from November
23, 1998, the date of our initial public offering, to December 31, 1998.
Holders
As of September 7, 1999, there were approximately 140 holders of record of
common units.
Distribution History
We paid the full minimum quarterly distribution of $0.45 per unit on all of
our common and subordinated units for the first quarter of 1999. In addition,
for the second quarter of 1999, we distributed $0.4625 ($0.0125 in excess of
the minimum quarterly distribution) on all of our outstanding common and
subordinated units. In accordance with the terms of our partnership agreement,
the general partner receives an increasing percentage of cash distributed in
excess of the minimum quarterly distribution. Accordingly, our general partner
received 15% of the distributions in excess of the minimum quarterly
distribution for the second quarter of 1999.
35
<PAGE>
SELECTED PRO FORMA FINANCIAL AND OPERATING DATA
The following unaudited Selected Pro Forma Financial and Operating Data are
derived from the historical financial statements of Plains All American
Pipeline; the Scurlock Permian businesses, formerly owned by Marathon Ashland
Petroleum; Wingfoot Ventures Seven, Inc., a wholly owned subsidiary of Goodyear
and the former owner of the All American Pipeline and the SJV Gathering System;
and our predecessor, the Plains Midstream Subsidiaries.
<TABLE>
<CAPTION>
Year Ended Six Months
December 31, 1998 Ended June 30, 1999
--------------------------- ---------------------------
Pro Pro Forma Pro Pro Forma
Forma (1) As Adjusted (2) Forma (1) As Adjusted (2)
---------- --------------- ---------- ---------------
(in thousands, except per unit and barrel amounts)
<S> <C> <C> <C> <C>
Income Statement Data:
Revenues.............. $2,817,051 $2,817,051 $1,705,586 $1,705,586
Cost of sales and
operations........... 2,710,157 2,710,157 1,649,327 1,649,327
Inventory market
valuation charge
(credit)............. 9,499 9,499 (9,499) (9,499)
---------- ---------- ---------- ----------
Gross margin.......... 97,395 97,395 65,758 65,758
---------- ---------- ---------- ----------
General and
administrative
expenses............. 34,183 34,183 16,791 16,791
Depreciation and
amortization......... 17,328 17,328 8,680 8,680
---------- ---------- ---------- ----------
Total expenses........ 51,511 51,511 25,471 25,471
---------- ---------- ---------- ----------
Operating income...... 45,884 45,884 40,287 40,287
Interest expense...... 22,109 18,106(3) 10,911 9,062(3)
Other expense......... -- -- 410 410
Interest and other
income............... (1,435) (1,435) (768) (768)
---------- ---------- ---------- ----------
Pro forma net income.. $ 25,210 $ 29,213 $ 29,734 $ 31,583
========== ========== ========== ==========
Pro forma net income
per unit............. $ 0.79 $ 0.84 $ 0.93 $ 0.91
========== ========== ========== ==========
Balance Sheet Data (at
end of period):
Working capital....... $ 3,712
Total assets.......... 1,006,786
Total long-term debt.. 240,314
Partners' capital..... 355,576
Other Data:
EBITDA(4)............. $ 74,146 $ 74,146 $ 39,826 $ 39,826
Maintenance capital
expenditures(5)...... 2,991 2,991 1,176 1,176
Operating Data:
Volumes (barrels per
day):
Lease gathering...... 282,400 282,400 316,900 316,900
Bulk purchases....... 212,100 212,100 189,300 189,300
Terminal
throughput(6)....... 79,800 79,800 79,200 79,200
Pipeline:
Tariff.............. 152,300 152,300 138,900 138,900
Margin(7)........... 49,200 49,200 55,400 55,400
---------- ---------- ---------- ----------
Total pipeline..... 201,500 201,500 194,300 194,300
========== ========== ========== ==========
</TABLE>
36
<PAGE>
- --------
(1) Reflects the acquisition of the Scurlock Permian businesses, the
acquisition of the All American Pipeline and the SJV Gathering System from
Goodyear, and the initial public offering and the transactions whereby
Plains All American Pipeline became the successor to the business of our
predecessor, as if such transactions took place on January 1, 1998.
(2) In addition to the transactions described in footnote (1) above, reflects
the proceeds from this offering, including interest savings resulting from
the repayment of debt with these proceeds as if the offering took place on
January 1, 1998.
(3) Reflects the use of proceeds from this offering to repay a portion of our
borrowings under our $160 million Plains Scurlock credit facility. Our
ability to repay this debt is dependent upon obtaining the consent of the
lenders under our $225 million bank credit facility. If we are unable to
obtain this consent, we will use the proceeds to repay a portion of the
borrowings under our bank credit facility. Since the interest rate under
the Plains Scurlock credit facility is higher than the interest rate for
our bank credit facility borrowings, failure to obtain this consent would
result in pro forma as adjusted interest expense of approximately $18.7
million and $9.3 million, for the twelve month period ended December 31,
1998 and the six month period ended June 30, 1999, respectively.
(4) EBITDA means earnings before interest expense, income taxes, depreciation
and amortization. Our EBITDA calculation excludes a non-cash inventory
market valuation charge of approximately $9.5 million for the year ended
December 31, 1998, and a non-cash inventory market valuation credit of
approximately $9.5 million for the six months ended June 30, 1999. EBITDA
provides additional information for evaluating our 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 and is not intended to be used in lieu of
GAAP presentations of results of operations and cash provided by operating
activities. Our EBITDA may not be comparable to EBITDA of other entities as
other entities may not calculate EBITDA in the same manner as we do.
(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 our existing capacity, whether through
construction or acquisition, are not considered maintenance capital
expenditures. Repair and maintenance expenditures associated with existing
assets that do not extend the useful life or expand operating capacity are
charged to expense as incurred.
(6) Represents total crude oil barrels delivered from the Cushing Terminal and
the Ingleside Terminal.
(7) Represents crude oil deliveries on the All American Pipeline.
37
<PAGE>
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
On November 23, 1998, we completed our initial public offering and the
transactions whereby we became the successor to the business of our
predecessor. The financial information below for Plains All American Pipeline
was derived from our audited consolidated financial statements as of December
31, 1998, and for the period from November 23, 1998 through December 31, 1998.
The financial information below for our predecessor was derived from the
audited combined financial statements of our predecessor, as of December 31,
1997, 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. The operating data for all periods is
derived from our records as well as the records of our predecessor. Commencing
May 1, 1999, the results of operations of the Scurlock Permian businesses are
included in the results of operations of Plains All American Pipeline.
Commencing July 30, 1998, the results of operations of the All American
Pipeline and the SJV Gathering System are included in the results of operations
of our predecessor and Plains All American Pipeline. The selected financial
data should be read in conjunction with the consolidated and combined financial
statements, including the notes thereto, included elsewhere in this prospectus,
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
Plains All Plains All
American American
Predecessor Pipeline Predecessor Pipeline
---------------------------------------------------- ------------ ----------- ----------
January 1, November 23, Six Months Ended
Year Ended December 31, 1998 to 1998 to June 30,
-------------------------------------- November 22, December 31, ----------------------
1994 1995 1996 1997 1998(1) 1998 1998 1999(2)
-------- -------- -------- -------- ------------ ------------ ----------- ----------
(in thousands, except for operating data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues............... $199,239 $339,825 $531,698 $752,522 $953,244 $176,445 $330,683 $1,318,284
Cost of sales and
operations............ 193,050 333,459 522,167 740,042 922,263 168,946 321,483 1,272,244
-------- -------- -------- -------- -------- -------- -------- ----------
Gross margin........... 6,189 6,366 9,531 12,480 30,981 7,499 9,200 46,040
-------- -------- -------- -------- -------- -------- -------- ----------
General and
administrative
expenses.............. 2,376 2,415 2,974 3,529 4,526 771 2,041 7,947
Depreciation and
amortization.......... 906 944 1,140 1,165 4,179 1,192 621 6,671
-------- -------- -------- -------- -------- -------- -------- ----------
Total expenses......... 3,282 3,359 4,114 4,694 8,705 1,963 2,662 14,618
-------- -------- -------- -------- -------- -------- -------- ----------
Operating income....... 2,907 3,007 5,417 7,786 22,276 5,536 6,538 31,422
Interest expense....... 3,550 3,460 3,559 4,516 11,260 1,371 1,828 7,913
Other expense.......... -- -- -- -- -- -- -- 410
Interest and other
income................ (115) (115) (90) (138) (572) (12) (581) (287)
-------- -------- -------- -------- -------- -------- -------- ----------
Net income (loss)
before provision
(benefit) in lieu of
income taxes.......... (528) (338) 1,948 3,408 11,588 4,177 5,291 23,386
Provision (benefit) in
lieu of income
taxes................. (151) (93) 726 1,268 4,563 -- 2,037 --
-------- -------- -------- -------- -------- -------- -------- ----------
Net income (loss)...... $ (377) $ (245) $ 1,222 $ 2,140 $ 7,025 $ 4,177 $ 3,254 $ 23,386
======== ======== ======== ======== ======== ======== ======== ==========
Balance Sheet Data
(at end of period):
Working capital........ $ 4,734 $ 3,055 $ 2,586 $ 2,017 N/A $ 9,331 $ 37,791 $ 3,712
Total assets........... 62,847 82,076 122,557 149,619 N/A 607,186 180,667 1,006,786
Related party debt:
Short-term........... -- 6,524 9,501 8,945 N/A 7,768 10,190 16,482
Long-term............ 35,854 32,095 31,811 28,531 N/A -- 31,143 --
Total long-term
debt(3)............... -- -- -- -- N/A 175,000 -- 289,350
Combined equity........ 2,858 2,613 3,835 5,975 N/A -- 37,928 --
Partners' capital...... -- -- -- -- N/A 277,643 -- 306,540
</TABLE>
38
<PAGE>
<TABLE>
<CAPTION>
Plains
Plains All All
American American
Predecessor Pipeline Predecessor Pipeline
--------------------------------------------- ------------ ----------- --------
January 1, November 23, Six Months Ended
Year Ended December 31, 1998 to 1998 to June 30,
------------------------------- November 22, December 31, --------------------
1994 1995 1996 1997 1998(1) 1998 1998 1999(2)
------ ------ ------ ------- ------------ ------------ ----------- --------
(in thousands, except for operating data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Other Data:
EBITDA(4).............. $3,928 $4,066 $6,647 $ 9,089 $ 27,027 $ 6,740 $ 7,740 $ 37,970
Cash flows from
operating activities.. 4,763 (5,800) 733 (12,869) 21,384 8,392 (2,984) 15,471
Cash flows from
investing activities.. (485) (721) (3,285) (1,854) (399,611) (3,089) (506) (146,806)
Cash flows from
financing activities.. (4,723) 6,457 2,759 14,321 386,154 200 32,767 137,965
Maintenance capital
expenditures(5)....... 274 571 1,063 678 1,479 200 455 327
Operating Data:
Volumes (barrels per
day):
Lease gathering........ 29,600 45,900 58,500 71,400 87,100 126,200 81,900 186,300
Bulk purchases......... -- 10,200 31,700 48,500 94,700 133,600 102,100 115,700
Terminal
throughput(6)......... 28,900 42,500 59,800 76,700 81,400 61,900 74,500 79,200
Pipeline:
Tariff................ -- -- -- -- 113,700 110,200 -- 123,200
Margin(7)............. -- -- -- -- 49,100 50,900 -- 55,400
------ ------ ------ ------- -------- ------- ------- --------
-- -- -- -- 162,800 161,100 -- 178,600
====== ====== ====== ======= ======== ======= ======= ========
</TABLE>
- -------
(1) Includes the historical operating results of the All American Pipeline and
the SJV Gathering System since July 30, 1998.
(2) Includes the historical operating results of the Scurlock Permian
businesses since May 1, 1999.
(3) Excludes related party debt.
(4) EBITDA means earnings before interest expense, income taxes, depreciation
and amortization. EBITDA is not a measurement presented in accordance with
GAAP and is not intended to be used in lieu of GAAP presentations of
results of operations and cash provided by operating activities. Our EBITDA
and the predecessor's EBITDA may not be comparable to EBITDA of other
entities as other entities may not calculate EBITDA in the same manner as
we do.
(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 our existing capacity, whether through
construction or acquisition, are not considered maintenance capital
expenditures. Repair and maintenance expenditures associated with existing
assets that do not extend the useful life or expand the operating capacity
are charged to expense as incurred.
(6) Represents total crude oil barrels delivered from the Cushing Terminal and
the Ingleside Terminal.
(7) Represents crude oil deliveries on the All American Pipeline.
39
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the financial condition and results of
operations for Plains All American Pipeline and its predecessor entity should
be read in conjunction with the historical consolidated and combined financial
statements and notes thereto included elsewhere in this prospectus. For more
detailed information regarding the basis of presentation for the following
financial information, see the notes to the historical consolidated and
combined financial statements.
Overview
We were formed in September of 1998 to acquire and operate the midstream
crude oil business and assets of Plains Resources Inc. and its wholly owned
subsidiaries. In the following discussion, we refer to the midstream
subsidiaries of Plains Resources as our predecessor. On November 23, 1998, we
completed our initial public offering and the transactions whereby we became
the successor to the business of our predecessor. Our operations are conducted
through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Scurlock
Permian, L.P. Plains All American Inc., a wholly owned subsidiary of Plains
Resources, is our general partner. We are engaged in interstate and intrastate
crude oil transportation, gathering and marketing as well as crude oil
terminalling and storage activities. Our operations are conducted primarily in
California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
Pipeline Operations. Our activities from pipeline operations generally
consist of transporting third-party volumes of crude oil for a tariff and
merchant activities designed to capture price differentials between the cost to
purchase and transport crude oil to a sales point and the price received for
such crude oil at the sales point. Tariffs on our pipeline systems vary by
receipt point and delivery point. The gross margin generated by our tariff
activities depends on the volumes transported on the pipeline and the level of
the tariff charged, as well as the fixed and variable costs of operating the
pipeline. Our ability to generate a profit on margin activities is not tied to
the absolute level of crude oil prices but is generated by the difference
between an index related price paid and other costs incurred in the purchase of
crude oil and an index related price at which we sell crude oil. We are well
positioned to take advantage of these price differentials due to our ability to
move purchased volumes on our pipeline systems. We combine reporting of gross
margin for tariff activities and margin activities due to the sharing of fixed
costs between the two activities.
Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage activities is dependent on the
throughput volume of crude oil stored and the level of fees generated at our
terminalling and storage facilities. Gross margin from our gathering and
marketing activities is dependent on our ability to sell crude oil at a price
in excess of our aggregate cost. These operations are not directly affected by
the absolute level of crude oil prices, but are affected by overall levels of
supply and demand for crude oil and fluctuations in market related indices.
During periods when the demand for crude oil is weak (as was the case in
late 1997, 1998 and the first quarter of 1999), the market for crude oil is
often in contango, meaning that the price of crude oil in a given month is less
than the price of crude oil in a subsequent month. A contango market has a
generally negative impact on marketing margins, but is favorable to the storage
business, because storage owners at major trading locations (such as the
Cushing Interchange) can simultaneously purchase production at low current
prices for storage and sell at higher prices for future delivery. When there is
a higher demand than supply of crude oil in the near term, the market is
backward, meaning that the price of crude oil in a given month exceeds the
price of crude oil in a subsequent month. A backward market has a positive
impact on marketing margins because crude oil gatherers can capture a premium
for prompt deliveries. We believe that the combination of our terminalling and
storage activities and gathering and marketing activities provides a counter-
cyclical balance which has a stabilizing effect on our operations and cash
flow.
40
<PAGE>
As we purchase crude oil, we establish a margin by selling crude oil for
physical delivery to third party users, such as independent refiners or major
oil companies, or by entering into a future delivery obligation with respect to
futures contracts on the NYMEX. Through these transactions, we seek to maintain
a position that is substantially balanced between crude oil purchases and sales
and future delivery obligations. We purchase crude oil on both a fixed and
floating price basis. As fixed price barrels are purchased, we enter into sales
arrangements with refiners, trade partners or on the NYMEX, which establishes a
margin and protects us against future price fluctuations. When floating price
barrels are purchased, we match those contracts with similar type sales
agreements with our customers, or likewise establish a hedge position using the
NYMEX futures market. From time to time, we will enter into arrangements which
will expose us to basis risk. Basis risk occurs when crude oil is purchased
based on a crude oil specification and location which is different from the
countervailing sales arrangement. Our policy is only to purchase crude oil for
which we have a market and to structure our sales contracts so that crude oil
price fluctuations do not materially affect the gross margin which we receive.
We do not acquire and hold crude oil futures contracts or other derivative
products for the purpose of speculating on crude oil price changes that might
expose us to indeterminable losses.
Recent Developments
On May 12, 1999, we completed the acquisition of Scurlock Permian LLC and
certain other pipeline assets from Marathon Ashland Petroleum LLC. Including
working capital adjustments and associated closing and financing costs, the
cash purchase price was approximately $141 million. The assets, liabilities and
results of operations of the Scurlock acquisition are included in our
Consolidated Financial Statements effective May 1, 1999.
Scurlock, previously a wholly owned subsidiary of Marathon Ashland
Petroleum, is engaged in crude oil transportation, gathering and marketing, and
operates with approximately 2,300 miles of active pipelines, numerous storage
terminals and a fleet of more than 250 trucks. Its largest asset is an 800-mile
pipeline and gathering system located in the Spraberry Trend in West Texas that
extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties,
Texas. The assets we acquired also include approximately one million barrels of
crude oil linefill.
On July 15, 1999, we completed the acquisition of the West Texas Gathering
System from Chevron Pipe Line Company for approximately $36 million. The assets
acquired include approximately 450 miles of crude oil transmission mainlines,
approximately 340 miles of associated gathering and lateral lines, and
approximately 2.9 million barrels of tankage located along the system. The West
Texas Gathering System is connected to our All American Pipeline at Wink,
Texas, and will provide us with access to the Midland, Texas crude oil
interchange.
On September 3, 1999, we completed the acquisition of a Louisiana crude oil
terminal facility and associated pipeline system from Marathon Ashland
Petroleum LLC for $1.5 million. The principal assets acquired include
approximately 300,000 barrels of crude oil storage and terminalling capacity
and a six-mile crude oil transmission system near Venice, Louisiana. The
current capacity of the terminal and pipeline system is approximately 10,000
barrels of crude oil per day. The Venice facility provides us with the
opportunity to access additional sources of supply in southern Louisiana.
Results of Operations
Results of Operations for the Six Months Ended June 30, 1999 and the Six
Months Ended June 30, 1998
In this section we discuss:
. our historical results of operations for the six months ended June 30,
1999;
. our predecessor's historical results of operations for the six months
ended June 30, 1998; and
. our pro forma results of operations for the six months ended June 30,
1998.
41
<PAGE>
The historical results of operations for the six months ended June 30, 1999
are derived from our historical financial statements, which include the results
of the Scurlock acquisition effective May 1, 1999. The historical results of
operations for the six months ended June 30, 1998 are derived from the combined
financial statements of our predecessor. The results of operations of our
predecessor for the six months ended June 30, 1998, do not include the results
of operations of the All American acquisition, which was completed in July
1998.
Our pro forma results of operations are derived from the historical
financial statements of Wingfoot (which reflect the historical operating
results of the All American Pipeline and the SJV Gathering System) and our
predecessor. The pro forma results of operations reflect pro forma adjustments
to the historical results of operations as if we had been formed and the All
American acquisition had taken place on January 1, 1998. The following pro
forma results of operations do not include pro forma adjustments related to the
Scurlock acquisition.
The following table reflects our operating results on a historical basis for
the 1999 period and compares those results to our predecessor's historical
results, as well as to our pro forma results for the 1998 period (unaudited)
(in thousands):
<TABLE>
<CAPTION>
Six Months Ended June 30,
------------------------------------
1998 1998 1999
------------- ----------- ----------
(Predecessor) (Pro Forma)
<S> <C> <C> <C>
Operating Results:
Revenues............................... $330,683 $706,239 $1,318,284
======== ======== ==========
Gross margin:
Pipeline............................. $ -- $ 30,768 $ 24,936
Gathering and marketing and
terminalling and storage............ 9,200 10,102 21,104
-------- -------- ----------
Total.............................. 9,200 40,870 46,040
General and administrative expense..... (2,041) (3,094) (7,947)
-------- -------- ----------
Gross profit........................... $ 7,159 $ 37,776 $ 38,093
======== ======== ==========
Net income............................. $ 3,254 $ 26,247 $ 23,386
======== ======== ==========
Average Daily Volumes (barrels):
Pipeline activities
Tariff activities.................... -- 143 123
Margin activities.................... -- 35 55
-------- -------- ----------
Total.............................. -- 178 178
======== ======== ==========
Lease gathering........................ 82 102 186
Bulk purchases......................... 102 102 116
Terminal throughput.................... 75 75 79
</TABLE>
For the six months ended June 30, 1999, we reported net income of $23.4
million, or $0.75 per unit, on total revenues of $1.3 billion compared to our
predecessor's net income of $3.3 million on total revenues of $330.7 million.
Pro forma net income was $26.2 million on total revenues of $706.2 million for
the six month period in 1998.
Pipeline Operations. Gross margin from pipeline operations was $24.9 million
for the first six months of 1999 compared to $30.8 million for the comparative
period of 1998 on a pro forma basis. Our predecessor did not generate pipeline
revenue for the six months ended June 30, 1998. The decrease from the prior
year resulted primarily from lower tariff transport volumes, partially due to
lower production from Exxon's Santa Ynez Field and the Point Arguello Field,
both offshore California. This decrease was partially offset by an increase in
gross margin from our pipeline merchant activities and approximately $0.8
million of pipeline gross
42
<PAGE>
margin from the Scurlock acquisition, for which two months of operations are
included in the six months ended June 30, 1999. Pipeline tariff revenues and
tariff transport volumes from the All American Pipeline were approximately
$22.8 million and 113,000 barrels per day, respectively, for the first half of
1999, compared to $33.9 million and 143,000 barrels per day, respectively, for
the comparative period of 1998. The decrease in tariff volumes was partially
offset by an increase in barrels shipped as part of our merchant activities.
Volumes related to such activities were 55,000 barrels per day for the six
months ended June 30, 1999, which is an approximate 20,000 barrel per day
increase in the volumes from the prior year's period on a pro forma basis.
Operations and maintenance expenses were $13.0 million for the first half of
1999 as compared to $14.4 million for the same period of 1998.
In July 1999, a wholly owned subsidiary of Plains Resources acquired Chevron
USA's 26% working interest in the Point Arguello Field and, subject to
regulatory approval, will be the operator of record. All of the volumes
attributable to Plains Resources' interest are committed for transportation on
the All American Pipeline and will be subject to our Marketing Agreement with
Plains Resources.
The following table sets forth the All American Pipeline average deliveries
per day within and outside California.
<TABLE>
<CAPTION>
Six Months Ended June 30,
--------------------------------
1998 1998 1999
------------- ---------- ------
(Predecessor) (Pro Forma)
(in thousands)
<S> <C> <C> <C>
Deliveries
Average daily volumes (barrels):
Within California.......................... -- 117 106
Outside California......................... -- 61 62
------ ------ ------
Total.................................... -- 178 168
====== ====== ======
</TABLE>
Gathering and Marketing Activities and Terminalling and Storage Activities.
Gross margin from terminalling, storage, gathering and marketing activities was
approximately $21.1 million for the first half of 1999. Approximately $6.2
million of this gross margin is attributable to the Scurlock acquisition which
was effective May 1, 1999. The Scurlock gross margin was generated on gathering
volumes of approximately 192,000 barrels per day and bulk purchase volumes of
approximately 71,000 barrels per day. Scurlock daily volumes are a two month
average of activity from the date of acquisition through June 30, 1999.
Excluding the Scurlock acquisition, gross margin from our gathering,
marketing, terminalling and storage activities was approximately $14.9 million
for the first six months of 1999, compared to $9.2 million and $10.1 million in
the prior year comparative period for our predecessor and on a pro forma basis,
respectively. The increase reflected in the 1999 period is due to an increase
in per barrel lease gathering margins, lease gathering volumes and storage
capacity leased at our crude oil terminal facilities. Lease gathering volumes
increased from an average of 102,000 barrels per day on a pro forma basis for
the first half of 1998 to approximately 121,000 barrels per day for the first
half of 1999. Bulk purchase volumes declined from approximately 102,000 barrels
per day for the first half of 1998 to approximately 92,000 barrels per day for
the first half of 1999. This decrease is primarily due to a lesser volume of
purchases associated with our contango inventory transactions and an increased
amount of tankage that was leased to third parties at the Cushing Terminal. The
1.1 million barrel expansion of the Cushing Terminal was placed in service
during the second quarter of 1999. Throughput volumes at our terminals averaged
approximately 79,000 barrels per day for the first half of 1999, up
approximately 5% as compared to the average of 75,000 barrels per day in the
1998 period. Average leased terminal capacity increased significantly from
approximately 935,000 barrels per month for the first half of 1998 to 2.0
million barrels per month for the first half of 1999.
General and administrative expenses were $7.9 million for the six months
ended June 30, 1999, compared to $2.0 million and $3.1 million for the same
period in 1998 for the predecessor and on a pro forma basis,
43
<PAGE>
respectively. The increase in 1999 as compared to the 1998 pro forma amount is
due to the Scurlock acquisition (approximately $3.4 million), increased
expenses as a result of the continued expansion of our activities and expenses
related to the operation of Plains All American Pipeline as a public entity.
These increases, in addition to general and administrative expenses associated
with the All American acquisition, account for the increase in general and
administrative expenses from the 1998 predecessor amount.
Depreciation and amortization expense was $6.7 million for the six months
ended June 30, 1999, compared to $0.6 million for the predecessor and $5.7
million on a pro forma basis, respectively, for the 1998 comparative period.
The increase in depreciation and amortization from the predecessor amount is
due to the Scurlock acquisition in May 1999 and the All American acquisition in
July 1998. The increase from the 1998 pro forma amount is attributable to the
Scurlock acquisition.
In March 1999, we adopted a plan to reduce staff in our pipeline operations
and to relocate certain functions. We incurred a charge to first quarter
earnings of approximately $410,000 in connection with such plan. This amount is
reflected as other expense in the accompanying consolidated income statement
for the six months ended June 30, 1999. We expect to continue to review our
cost structure as we further integrate our recent acquisitions into our
operations.
Interest expense was $7.9 million for the first half of 1999 compared to
$1.8 million reported by the predecessor and $6.4 million on a pro forma basis
for the same period in 1998. The increase in interest expense from the
predecessor level is due to interest associated with the debt incurred for the
Scurlock acquisition and the All American acquisition. The increase from the
1998 pro forma amount is primarily attributable to the Scurlock acquisition and
a slight increase in interest expense related to hedged inventory transactions.
Pro Forma Comparison of the Years Ended December 31, 1997 and 1998
In the discussion which follows, we are presenting a comparison of our pro
forma results for the 1997 and 1998 years. The pro forma adjustments to the
historical results of operations assume we had been formed and the All American
acquisition had taken place on January 1, 1997. The following table sets forth
certain pro forma financial and operating information of Plains All American
Pipeline for the periods presented. The following pro forma financial and
operating information does not include pro forma adjustments related to the
Scurlock acquisition.
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------
1997 1998
---------- ----------
(pro forma, in
thousands)
<S> <C> <C>
Operating Results:
Revenues............................................. $1,746,491 $1,568,853
========== ==========
Gross margin:
Pipeline........................................... $ 70,078 $ 50,893
Gathering and marketing and terminalling and
storage........................................... 14,131 23,228
---------- ----------
Total............................................ 84,209 74,121
General and administrative expense................... (6,182) (6,501)
---------- ----------
Gross profit......................................... $ 78,027 $ 67,620
========== ==========
Net income (loss).................................... $ (10,097) $ 43,910
========== ==========
Average Daily Volumes (barrels):
Pipeline activities
Tariff activities.................................. 165 125
Margin activities.................................. 30 49
---------- ----------
Total.............................................. 195 174
========== ==========
Lease gathering...................................... 94 113
Bulk purchases....................................... 49 98
Terminal throughput.................................. 77 80
</TABLE>
44
<PAGE>
For the year ended December 31, 1998, our 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 our purchase price allocation to property and
equipment and pipeline linefill, an impairment charge would not have been
required had we actually acquired Wingfoot effective January 1, 1997. Excluding
this impairment charge, our pro forma net income for 1997 would have been $54.1
million. We 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; and
. fewer tariff barrels moved to West Texas offset by increasing margin
barrels.
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.
<TABLE>
<CAPTION>
Year Ended
December 31,
--------------------------
1997 1998
------------ ------------
(pro forma, in thousands)
<S> <C> <C>
Deliveries:
Average daily volumes (barrels):
Within California............................ 127 113
Outside California........................... 68 61
------------ ------------
Total...................................... 195 174
============ ============
</TABLE>
Terminalling and Storage Activities and Gathering and Marketing Activities.
We reported gross margin of $23.2 million from our 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. After deducting 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 including property taxes, electricity, fuel, labor,
repairs and certain other expenses, decreased to $24.9 million
45
<PAGE>
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.
Historical Analysis of Three Years Ended December 31, 1998
The historical results of operations discussed below are derived from our
historical financial statements for the period from November 23, 1998, through
December 31, 1998, and the combined financial statements of our predecessor for
the period from January 1, 1998, through November 22, 1998, which in the
following discussion are combined and referred to as the year ended December
31, 1998. Commencing July 30, 1998, (the date of 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.
For 1998, we 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 from July 30, 1998.
The following table sets forth historical financial and operating
information of Plains All American Pipeline for the periods presented:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1996 1997 1998
-------- -------- ----------
(in thousands)
<S> <C> <C> <C>
Operating Results:
Revenues..................................... $531,698 $752,522 $1,129,689
======== ======== ==========
Gross margin
Pipeline................................... $ -- $ -- $ 16,768
Terminalling and storage and gathering and
marketing................................. 9,531 12,480 21,712
-------- -------- ----------
Total.................................... 9,531 12,480 38,480
General and administrative expense........... (2,974) (3,529) (5,297)
-------- -------- ----------
Gross profit................................. $ 6,557 $ 8,951 $ 33,183
======== ======== ==========
Net income................................... $ 1,222 $ 2,140 $ 11,202
======== ======== ==========
Average Daily Volumes (barrels)
Pipeline activities
Tariff activities.......................... -- -- 113
Margin activities.......................... -- -- 50
-------- -------- ----------
Total...................................... -- -- 163
======== ======== ==========
Lease gathering.............................. 59 71 88
Bulk purchases............................... 32 49 95
Terminal throughput.......................... 59 77 80
</TABLE>
Pipeline Operations. As noted above, our results of operations include
approximately five months of operations of the All American Pipeline and the
SJV Gathering System which were acquired effective July 30,
46
<PAGE>
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 $10.1
million.
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. After
deducting interest expense associated with contango inventory transactions,
gross margin for 1998 was $21.0 million, representing an increase of
approximately 81% over the 1997 amount. We 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 our 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 in
1998 is due to the acquisition of the All American Pipeline and the SJV
Gathering System in July 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 our 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
$0.9 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
Scurlock Acquisition
On May 12, 1999, Plains Scurlock Permian, L.P., a limited partnership of
which Plains All American Inc. is the general partner and Plains Marketing,
L.P. is the limited partner, completed the Scurlock Acquisition. Including
working capital adjustments and associated closing and financing costs, the
cash purchase price was approximately $141 million.
Financing for the Scurlock acquisition was provided through:
. a borrowing of approximately $92 million under Plains Scurlock's limited
recourse bank facility with BankBoston, N.A.,
. the sale to the general partner of 1.3 million Class B common units of
Plains All American Pipeline for a total cash consideration of $25
million representing a purchase price of $19.125 per unit, the price
equal to the market value of our common units on May 12, 1999, and
. a $25 million draw under our existing revolving credit agreement.
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<PAGE>
The Class B common units are pari passu with common units with respect to
quarterly distributions, and after six months are convertible into common units
upon approval by a majority of the common units voting at a meeting of
unitholders. If the approval of a conversion by the common unitholders is not
obtained within 120 days of a request by the Class B unitholders, the Class B
unitholders will be entitled to receive distributions, on a per unit basis,
equal to 110% of the amount of distributions paid on a common unit, with such
distribution right increasing to 115% if such approval is not secured within 90
days after the end of the initial 120-day period. Class B units have the same
voting rights as the common units.
Chevron Acquisition
On July 15, 1999, Plains Scurlock Permian, L.P. completed the acquisition of
a West Texas crude oil pipeline and gathering system from Chevron Pipe Line
Company for approximately $36 million, including transaction costs. The
principal assets acquired include approximately 450 miles of crude oil
transmission mainlines, approximately 340 miles of associated gathering and
lateral lines and approximately 2.9 million barrels of crude oil storage and
terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler
Counties, Texas. Financing for the Chevron acquisition was provided by a draw
under the term loan portion of the Plains Scurlock credit facility.
Credit Agreements
The Plains Scurlock credit facility consists of a five-year $126.6 million
term loan and a three-year $35 million revolving credit facility. The Plains
Scurlock credit facility is nonrecourse to Plains All American Pipeline, Plains
Marketing, L.P. and All American Pipeline, L.P. and is secured by the Scurlock
assets and the West Texas Gathering System. Borrowings under the term loan bear
interest at LIBOR plus 3% and under the revolving credit facility at LIBOR plus
2.75%. A commitment fee equal to 0.5% per year is charged on the unused portion
of the revolving credit facility. The revolving credit facility, which may be
used for borrowings or letters of credit to support crude oil purchases,
matures in May 2002. The term loan provides for principal amortization of $0.7
million annually beginning May 2000, with a final maturity of May 2004. As of
June 30, 1999, letters of credit of approximately $15.2 million were
outstanding under the revolver and borrowings of $90 million were outstanding
under the term loan.
Concurrently with the closing of the initial public offering, we entered
into a $225 million bank credit agreement that includes a $175 million term
loan facility and a $50 million revolving credit facility. The bank credit
agreement is secured by a lien on substantially all of our assets. We may
borrow up to $50 million under the revolving credit facility for acquisitions,
capital improvements, working capital and general business purposes. At June
30, 1999, we had $175 million outstanding under the term loan facility,
representing indebtedness assumed from the general partner and $25 million
outstanding under the revolving credit facility. The term loan facility matures
in 2005, and no principal is scheduled for payment prior to maturity. The term
loan facility may be prepaid at any time without penalty. The revolving credit
facility expires in November 2000.
We have a $175 million letter of credit and borrowing facility, the purpose
of which is to provide standby letters of credit to support the purchase and
exchange of crude oil for resale and borrowings to finance crude oil inventory
which has been hedged against future price risk or designated as working
inventory. Aggregate availability under the letter of credit facility for
direct borrowings and letters of credit is limited to a borrowing base which is
determined monthly based on certain of our current assets and current
liabilities, primarily crude oil inventory and accounts receivable and accounts
payable related to the purchase and sale of crude oil. This facility is secured
by a lien on substantially all of our assets. At June 30, 1999, the borrowing
base under the letter of credit facility was $175 million. The letter of credit
facility has a $40 million sublimit for borrowings to finance hedged
inventories of crude oil. At June 30, 1999, there were letters of credit of
approximately $90.1 million and borrowings of $22 million outstanding under
this facility.
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<PAGE>
All of our credit facilities contain prohibitions on distributions on, or
purchases or redemptions of, units if any default or event of default is
continuing. In addition, our facilities will contain various covenants limiting
our ability to:
. incur indebtedness;
. grant liens;
. sell assets in excess of certain limitations;
. engage in transactions with affiliates;
. make investments;
. enter into hedging contracts; and
. enter into a merger, consolidation or sale of assets.
Each of our facilities treats a change of control as an event of default. In
addition, the terms of our letter of credit facility and our bank credit
agreement require us to maintain:
. a current ratio of 1.0 to 1.0, as defined in our credit agreement;
. a debt coverage ratio which is not greater than 5.0 to 1.0;
. an interest coverage ratio which is not less than 3.0 to 1.0;
. a fixed charge coverage ratio which is not less than 1.25 to 1.0; and
. debt to capital ratio of not greater than .60 to 1.0.
The terms of the Plains Scurlock credit facility require us to maintain at the
end of each quarter:
. a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June
30, 2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to
1.0 thereafter; and
. an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through
June 30, 2000 and 2.5 to 1.0 thereafter.
In addition, the Plains Scurlock credit facility contains limitations on the
Plains Scurlock Permian operating partnership's ability to make distributions
to us if its indebtedness and current liabilities exceed certain levels as well
as the amount of expansion capital it may expend. Following the completion of
this offering, we intend to amend or replace our existing credit facilities to
enable us to consolidate our various credit facilities and increase the size to
approximately $450 million to $500 million. This will increase the unused
availability of the credit facilities and, therefore, our liquidity and
flexibility. At the closing of this offering, the aggregate balance outstanding
on all of our existing facilities will be approximately $278 million. While we
are in discussions with our principal lenders under each of our credit
facilities, we cannot assure you that we will be successful in obtaining
borrowing capacity in excess of what is currently available to us or that the
terms under any new or amended facility will be as or more favorable to us than
those contained in our existing facilities.
Partnership Distributions
On July 22, 1999, we declared a cash distribution of $0.4625 per unit on our
outstanding common units, Class B common units and subordinated units. The
distribution was paid on August 13, 1999, to holders of record of the units on
August 3, 1999, and represents an increase of $.0125 per unit over the minimum
quarterly distribution of $0.45 per unit. The total distribution paid was
approximately $14.9 million, with approximately $6.1 million paid to our public
unitholders and the remainder paid to the general partner for its limited and
general partner interests.
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Investing and Financing Activities
Six months ended June 30, 1998 as compared to six months ended June 30,
1999. Net cash flows used in investing activities were $0.5 million and $146.8
million for the six months ended June 30, 1998 and 1999, respectively.
Investing activities for the 1999 period include payments of approximately
$135.9 million related to the Scurlock acquisition (net of Scurlock cash on
hand at the acquisition date) and a $6.0 million deposit on the Chevron asset
acquisition. Investing activities also include payments for expansion capital
of $4.8 million and maintenance capital of $0.4 million for the six months
ended June 30, 1999. Approximately $3.3 million related to the expansion of
the Cushing Terminal is included in 1999 expansion capital payments.
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 capacity, whether through construction or acquisition, are not
considered maintenance capital expenditures. Repair and maintenance
expenditures associated with existing assets that do not extend the useful
life or expand the operating capacity are charged to expense as incurred.
While the actual level of maintenance capital expenditures will vary from year
to year, we expect these expenditures to be between $4 million and $5 million
for 2000. It is anticipated that these maintenance capital expenditures will
be funded from cash flows generated by operating activities.
Net cash flows provided by financing activities were approximately $138.0
million and $32.8 million for the six months ended June 30, 1999 and 1998,
respectively. Financing activities for the six months ended June 30, 1999
include $25 million of proceeds from the Class B common units which were
issued in connection with the Scurlock acquisition. Proceeds from borrowings
under the revolving credit facility and the Plains Scurlock credit facility
were approximately $187.6 million for the six months ended June 30, 1999. Such
amounts include approximately $117.0 million borrowed to fund the Scurlock
acquisition and approximately $6.0 million borrowed to fund a deposit paid on
the Chevron asset acquisition, which closed in July 1999. Repayments under the
revolving credit facility and Plains Scurlock credit facility were
approximately $72.6 million during the first six months of 1999. Financing
activities include approximately $24.2 million and $17.9 million in short-term
borrowings for the six months ended June 30, 1999 and 1998, respectively, and
approximately $11.9 million and $18.0 million of repayments for the respective
periods, related to hedged crude oil inventory transactions. Financing
activities for the 1998 period include a $28.7 million capital contribution
from Plains Resources to our predecessor.
Financing activities for the first six months of 1999 include cash
distributions paid to unitholders of approximately $19.7 million.
Approximately $8.4 million of such amount was paid to our public unitholders,
with the remainder paid to the general partner for its limited partner and
general partner interests.
Year ended December 31, 1998 as compared to year ended December 31, 1997.
Net cash flows used in investing activities were approximately $402.7 million
for us and our predecessor combined for the year ended December 31, 1998.
These amounts include:
. approximately $394.0 million paid in connection with the acquisition of
the All American Pipeline and the SJV Gathering System in July 1998; and
. approximately $4.2 million related to the Cushing Terminal expansion.
Net cash flows used in investing activities for our predecessor for 1997
were approximately $1.8 million.
Net cash flows from financing activities were approximately $386.4 million
for us and our predecessor combined for the year ended December 31, 1998.
Financing activities for 1998 include the following related to the acquisition
of the All American Pipeline and the SJV Gathering System:
. approximately $300 million from borrowings and $15 million in repayments
under the senior credit facility;
. a capital contribution from Plains Resources of approximately $113.7
million; and
. approximately $9.9 million of financing costs.
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<PAGE>
Financing activities for 1998 related to our initial public offering
include:
. proceeds of approximately $244.7 million;
. the payment of distributions to the general partner of approximately
$241.7 million; and
. the payment of approximately $3.0 million of expenses.
Net cash provided by financing activities for our predecessor for 1997 was
approximately $14.3 million. Financing activities during 1998 and 1997 include
proceeds of $31.8 million and $39.0 million, respectively, from short-term
borrowings and $40.0 million and $21.0 million, respectively, of repayments
related to crude oil inventory transactions at the Cushing Terminal.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board 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, 2000. SFAS 133 requires that all derivative
instruments be recorded on the balance sheet at their fair value. Changes in
the fair value of derivatives are recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction and, if so, the type of hedge transaction. For fair
value hedge transactions in which we are hedging changes in an asset's,
liability's, or firm commitment's fair value, changes in the fair value of the
derivative instrument will generally be offset in the income statement by
changes in the hedged item's fair value. For cash flow hedge transactions, in
which we are hedging the variability of cash flows related to a variable-rate
asset, liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income. The gains
and losses on the derivative instrument that are reported in other
comprehensive income will be reclassified as earnings in the periods in which
earnings are affected by the variability of the cash flows of the hedged item.
We are required to adopt this statement beginning in 2001. We have not yet
determined the effect that the adoption of SFAS 133 will have on our financial
position or results of operations.
Year 2000
Year 2000 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, 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 us because we directly depend on our own
applications, equipment and systems and indirectly depend on those of third
parties with which we do business. Our key applications, equipment, and
automated systems consist of:
. financial systems applications;
. computer hardware and equipment;
. embedded chip systems; and
. third-party developed software.
Year 2000 Project. In order to address the year 2000 issue, we have
established a year 2000 project team. As we evaluate new properties for
acquisition, we perform a pre-acquisition assessment to determine year 2000
readiness. Upon acquisition, we incorporate these properties into the year 2000
project. The project team coordinates the five phases of the year 2000 project.
Those phases are:
. assessment;
. remediation;
. testing;
. implementation of the necessary modifications; and
. contingency planning.
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The year 2000 project also includes the evaluation of the extent and status
of the year 2000 compliance efforts of third parties who are material to our
operations and business units. We have retained a year 2000 consulting firm to
perform an assessment of certain field equipment which has embedded chip
systems. We and the consulting firm are currently performing the necessary
remediation, testing and modification of these embedded chip systems which are
critical to our field operations.
Year 2000 Project Status. The assessment phase for all key applications,
equipment, and automated systems is complete. The remaining phases of the
project involving remediation, testing, and implementation of necessary
modifications are proceeding concurrently. The following table sets forth the
estimated dates of completion of the year 2000 project for our key
applications, equipment, and automated systems:
<TABLE>
<CAPTION>
Key Applications, Equipment
and Automated Systems Estimated Completion Date
------------------------------------ -------------------------
<S> <C>
Third Party Developed Software September 1999
Computer Hardware and Equipment October 1999
Embedded Chip Systems October 1999
Financial Systems Applications October 1999
</TABLE>
An integral part of the year 2000 project is communication with our critical
suppliers and key customers and partners to determine whether their operations
and/or services or products will be year 2000 ready. We have contacted
substantially all of these third parties requesting information on the status
of their year 2000 efforts and are currently evaluating responses and making
additional inquiries as needed.
Contingency Planning. As the other phases of the year 2000 project near
completion, we are evaluating which of our business activities may still be
vulnerable to a year 2000 disruption. We are developing appropriate contingency
plans for each material "at risk" business activity to provide an alternative
means of functioning in an attempt to minimize the effect of the potential year
2000 disruptions, both internally and on third parties. The contingency plans
are expected to be completed by December 1, 1999. Communications with third
parties that are critical to our business will continue throughout the
remainder of 1999, and we plan to develop contingency plans to the extent
necessary to address any concerns regarding the year 2000 readiness of such
third parties.
Costs of the Year 2000 Project. From November 23, 1998, the date we acquired
the business of the predecessor, through June 30, 1999, we have incurred
approximately $180,000 as our share of expenses for Plains Resources' year 2000
project, of which approximately $35,000 are costs paid to third parties. Prior
to November 23, 1998, the predecessor incurred approximately $242,000 to
address the year 2000 issue. While the total cost of the year 2000 project is
still being evaluated, we currently estimate that the costs to be incurred in
the remainder of 1999 and 2000 are between $400,000 and $500,000. We anticipate
that the majority of these estimated costs will be internal costs. We expect to
fund these expenditures with cash from operations or borrowings.
Risk of Non-Compliance. The items that pose the greatest year 2000 risks for
us if implementation of the year 2000 project is not successful are our
financial systems applications, our pipeline supervisory control and data
acquisition ("SCADA") systems and embedded chip systems in our field equipment.
The potential problems if the year 2000 project is not successful with respect
to the financial systems applications are disruptions of our revenue gathering
from and distribution to our customers and vendors and the inability to perform
our other financial and accounting functions. Failures of SCADA systems or
embedded chip systems in our field equipment or our customers' equipment could
disrupt our crude oil transportation, terminalling and storage activities and
our gathering and marketing activities.
While we believe that the year 2000 project will substantially reduce the
risks associated with the year 2000 issue, there can be no assurance that we
will be successful in completing each and every aspect of the project on
schedule, and if successful, that the project will have the expected results.
Due to the general uncertainty inherent in the year 2000 issue, we cannot
conclude that our failure or the failure of third parties to
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achieve year 2000 compliance will not adversely affect our financial position,
results of operations or cash flows. Specific factors that might affect the
success of our year 2000 efforts and the occurrence of a year 2000 disruption
or expense include:
. our failure or the failure of our consultant to properly identify
deficient systems;
. the failure of the selected remedial action to adequately address any
deficiencies;
. our failure or our consultants' failure to complete the remediation in a
timely manner, due to shortages of qualified labor or other factors;
. unforeseen expenses related to the remediation of existing systems or the
transition to replacement systems; and
. the failure of third parties to become compliant or to adequately notify
us of potential non-compliance.
Quantitative and Qualitative Disclosures about Market Risks
We are exposed to various market risks, including volatility in crude oil
commodity prices and interest rates. To manage such exposure, we monitor our
inventory levels, current economic conditions and our expectations of future
commodity prices and interest rates when making decisions with respect to risk
management. We do not enter into derivative transactions for speculative
trading purposes. Substantially all of our derivative contracts are exchanged
or traded with major financial institutions and the risk of credit loss is
considered remote.
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:
<TABLE>
<CAPTION>
Change in Fair
Fair Value from 10%
At June 30, 1999 Value Adverse Price Change
---------------- ----- --------------------
(in millions)
<S> <C> <C>
Crude oil futures contracts...................... $(2.3) $(2.0)
</TABLE>
Interest Rate Risk. Our debt instruments are sensitive to market
fluctuations in interest rates. The table below presents principal payments and
the related weighted average interest rates by expected maturity dates for debt
outstanding at June 30, 1999. Our variable rate debt bears interest at LIBOR
plus the applicable margin. The average interest rates presented below are
based upon rates in effect at June 30, 1999. The carrying value of variable
rate bank debt approximates fair value as interest rates are variable, based on
prevailing market rates.
<TABLE>
<CAPTION>
Expected Year of Maturity
---------------------------------------------------------
Fair
1999 2000 2001 2002 2003 Thereafter Total Value
----- ----- ---- ---- ---- ---------- ------ ------
(dollars in millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Liabilities:
Short-term debt--
variable rate.......... $22.0 -- -- -- -- -- $ 22.0 $ 22.0
Average interest
rate................. 6.30% -- -- -- -- -- 6.30%
Long-term debt--variable
rate................... -- $25.7 $0.7 $0.7 $0.7 $262.2 $290.0 $290.0
Average interest
rate................. -- 6.42% 8.17% 8.17% 8.17% 7.07% 7.07%
</TABLE>
Interest rate swaps and collars are used to hedge underlying debt
obligations. These instruments hedge specific debt issuances and qualify for
hedge accounting. The interest rate differential is reflected as an adjustment
to interest expense over the life of the instruments. At June 30, 1999, we had
interest rate swap and collar arrangements for an aggregate notional principal
amount of $265 million, which positions had an aggregate value of approximately
$8.9 million as of such date. In August 1999, we terminated our swap
arrangements on an aggregate notional principal amount of $175 million and we
received consideration of approximately $10.8 million. Additionally, we entered
into new collar arrangements on a notional amount of $125 million.
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BUSINESS
We are a publicly traded Delaware limited partnership engaged in interstate
and intrastate crude oil pipeline transportation, terminalling and storage, as
well as gathering and marketing activities. We were formed in September 1998 to
acquire and operate the midstream crude oil business and assets of Plains
Resources Inc. In the last year, we have grown through acquisitions and
internal development to become one of the largest terminal operators, gatherers
and marketers of crude oil in the United States. We transport, terminal, gather
and market an aggregate of approximately 850,000 barrels of crude oil per day.
The acquisitions we completed during 1999 complemented our existing asset base
and enabled us to reduce costs, increase revenues and increase our quarterly
distribution per unit in the second quarter of 1999 from $0.45 to $0.4625 per
unit.
Market Overview
We discuss below four important factors that we believe create profit
opportunities for us within the United States crude oil midstream industry.
. Regional crude oil supply and demand imbalances exist in the United
States, particularly in the Midwest. The crude oil pipeline
infrastructure in the United States is primarily configured to transport
crude oil from the exterior portions of the country, which have access to
waterborne cargoes, to the landlocked Midwest region of the country. The
Midwest experienced a shortfall of regional production compared to
regional demand of approximately 2.8 million barrels per day in 1998. In
the 15-year period ended December 31, 1998, the supply shortfall in the
Midwest increased by approximately 1.1 million barrels per day as
regional production declined and refining demand increased. As a result,
Midwest refiners obtain a substantial portion of their crude oil
feedstock requirements from sources outside of the region. Because of our
asset base, we are well-positioned to supply a portion of this excess
demand. For example, we have the ability to source crude oil in areas of
excess supply, such as California and the Gulf Coast, by utilizing our
gathering and marketing assets. We are then able to transport the crude
oil via our own or third-party pipelines to our terminalling and storage
facilities, from which the crude oil can be redelivered to Midwest
refineries in accordance with their processing needs.
. The volume of foreign crude oil imported into the United States is
growing. In the last ten years, the United States has become more
dependent on foreign crude oil. In 1998, the United States imported
approximately 8.7 million barrels per day of crude oil as compared to 5.1
million barrels per day of crude oil in 1988. This increase, as well as
any future increase in the volume of foreign crude oil imported into the
United States, creates potential profit opportunities for us in both our
pipeline transportation business and our terminalling and storage
business. As additional foreign crude oil is imported into an area of
balanced supply and demand, it has the potential to displace regional
production, thereby forcing producers to seek alternative markets for
their crude oil. For example, in California, where supply and demand is
nearly balanced, foreign imports of crude oil displace regional
production, some of which is then transported via our All American
Pipeline to alternative markets in West Texas. Additionally, foreign
crude oil imports are typically delivered via tanker in large quantities,
which is incompatible with the needs of many Midwest refiners, who
typically require deliveries in much smaller quantities. As a result,
these refiners frequently utilize our Cushing Terminal to store bulk
deliveries of foreign crude oil for ratable delivery to them according to
their processing requirements.
. The feedstock requirements of United States refiners are diverse. Most
refineries in the United States consist of a unique configuration of
process units designed to maximize the profits generated by converting
crude oil into higher value petroleum products. Refiners are constantly
trying to improve their processing economics by finding the best
combination of crude oil feedstocks for their particular refinery
configuration. Primarily as a result of the increased volume of foreign
crude oil imported into the United States, there are over 100 grades of
crude oil available to refiners. Our Cushing Terminal and other similar
assets provide Midwest refineries with the opportunity to segregate or
blend various grades of crude oil to meet their refining specifications.
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. Infrastructure modifications will be necessary to meet the evolving needs
of the United States crude oil midstream industry. As energy markets
continue to evolve, further modifications to pipeline, terminal and
storage infrastructure will be necessary. We feel that the strategic
location of our asset base allows us to capitalize on shifts in supply
and demand for crude oil and related products. For example, because of
the increase in the volume of foreign crude oils delivered to the Gulf
Coast, the Seaway Pipeline System has announced an expansion project that
will increase the capacity on its pipeline system that transports crude
oil from the Gulf Coast to the Cushing Interchange. We believe that this
expansion project will create additional demand for our terminalling and
storage facilities at the Cushing Terminal.
Business Strategy
Our business strategy is to capitalize on the regional crude oil supply and
demand imbalances which exist in the continental United States by combining the
strategic location and unique capabilities of our transportation and
terminalling assets with our extensive marketing and distribution expertise to
generate sustainable earnings and cash flow for our unitholders.
We intend to execute our business strategy by:
Increasing and optimizing throughput on our various pipeline and gathering
assets. We continually attempt to add volumes of crude oil for transportation
on our pipeline systems. We also try to optimize the logistics of our crude oil
movements. Examples of some of the actions we have taken are listed below.
. We have obtained the necessary permit for, and intend to install, a
pipeline underneath the Mississippi River to connect the two segments of
our Ferriday pipeline system. Completion of this connection will
increase our market alternatives for the production that this pipeline
system serves. It will also provide us with the opportunity to increase
the utilization of the 348,000 barrels of storage capacity available on
this system.
. We have installed four truck injection stations on the West Texas
Gathering System and will install an additional five stations by the end
of October. Our trucks are used to pick up crude oil produced in the
areas adjacent to the West Texas Gathering System and deliver these
volumes into the pipeline. These additional injection stations will
allow us to reduce the distance of our truck hauls in this area,
increase the utilization of our pipeline assets and reduce our operating
costs.
. We are in the process of acquiring additional pumping equipment at the
Venice Terminal. This additional equipment will allow us to double the
volume at this terminal at what we consider to be a low cost.
. We have leased a previously dormant 8-inch pipeline that connects our
SJV Gathering System to production in the Lost Hills field in the San
Joaquin Valley. This line will provide the opportunity to increase the
utilization of our SJV Gathering System at an attractive incremental
cost.
. We are in the process of providing bi-directional capacity on a segment
of the West Texas Gathering System. This modification will provide us
with the opportunity to increase the utilization of the 1.8 million
barrels of tankage we own at our Monahans and Wink stations.
We believe we have significant additional opportunities to continue to
increase margins through actions consistent with those outlined above, all of
which should help us to improve the utilization of our assets at what we
believe to be minimal incremental costs.
Realizing cost efficiencies through operational improvements and potential
strategic alliances. We believe that we are one of the most efficient operators
in our industry. We have been able to lower operating costs through the
significant time and effort we have spent integrating our acquisitions into our
existing operations. In each of the four acquisitions that we have completed
within the last fourteen months, we immediately began to reorganize the
operations and lower operating expenses. Our efforts to lower operating
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<PAGE>
costs do not end after our initial post-acquisition restructuring, as evidenced
by the further restructuring of our All American Pipeline operations in March
and September of 1999. We will continue to aggressively monitor our cost
structure and believe that we should be able to recognize additional cost
reductions in the future. We also believe that there may be opportunities to
reduce costs through joint ventures with pipeline systems operated by third
parties.
Utilizing our Cushing Terminal and our other assets to service the needs of
refiners and to profit from merchant activities that take advantage of crude
oil pricing and quality differentials. Cushing, Oklahoma is the largest trading
and pipeline hub for movements of crude oil into the Midwest. Our Cushing
Terminal is connected to all of the major pipeline systems in the Cushing
Interchange area. As a result, we have access to significant volume and over 50
grades of crude oil. Since a specific grade of crude oil will have a different
value to each refinery, our knowledge of the crude oil market combined with our
access to the various grades of crude oil at the Cushing Interchange present
opportunities to take advantage of crude oil pricing and quality differentials.
We completed an approximate 1.1 million barrel expansion project at our Cushing
Terminal that increased our total capacity there by approximately 55%. This
additional capacity enhances our merchant capabilities and our ability to
service our terminalling and storage customers. We believe we have similar
opportunities, but on a smaller scale, with other storage facilities associated
with our pipeline systems and barge terminals.
Pursuing strategic and accretive acquisitions of crude oil pipeline assets,
gathering systems and terminalling and storage facilities which complement our
existing asset base. We actively pursue opportunities to purchase assets that
can increase our cash flow per unit. Since our initial public offering in
November 1998 we have completed the following acquisitions:
. On May 12, 1999, we completed the acquisition of Scurlock Permian LLC
and certain other pipeline assets from Marathon Ashland Petroleum LLC
for approximately $141 million. Scurlock is engaged in crude oil
transportation, gathering and marketing, operating with more than 2,400
miles of active pipelines, numerous storage terminals and a fleet of
more than 250 trucks. Its largest asset is an 800-mile pipeline and
gathering system located in the Spraberry Trend in West Texas. The
Spraberry Pipeline System is located in close proximity to the West
Texas Gathering System, with which it interconnects at Midland, Texas,
where third-party transportation to Cushing is available.
. On July 15, 1999, we completed the acquisition of the West Texas
Gathering System from Chevron Pipe Line Company for approximately $36
million. The assets acquired include approximately 450 miles of crude
oil transmission mainlines, approximately 340 miles of associated
gathering and lateral lines and approximately 2.9 million barrels of
previously underutilized tankage located along the system. The West
Texas Gathering System is connected to our All American Pipeline at
Wink, Texas, and provides access to the Midland, Texas crude oil
interchange.
. On September 3, 1999, we completed the acquisition of a Louisiana crude
oil terminal facility and associated pipeline system from Marathon
Ashland Petroleum LLC for $1.5 million. The principal assets acquired
include approximately 300,000 barrels of crude oil storage and
terminalling capacity and a six-mile crude oil transmission system near
Venice, Louisiana. The current capacity of the terminal and pipeline
system is approximately 10,000 barrels of crude oil per day. The Venice
facility provides us with the opportunity to access additional sources
of supply in southern Louisiana.
Because each of these acquisitions complemented our existing asset base, we
are able to reduce costs and increase revenues. The acquisition of Scurlock
Permian enabled us to increase our distribution by $0.0125 per unit in the
second quarter of 1999.
We believe that the consolidation of major integrated oil companies will
provide us with acquisition opportunities as these companies divest non-
strategic assets, including pipeline, terminals and gathering and marketing
assets. We routinely evaluate acquisition and expansion opportunities and have
made contact with several owners of assets that we believe are attractive
opportunities for us. However, we currently have no commitments for material
acquisitions or expansions at this time.
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<PAGE>
Competitive Strengths
We believe we are well-positioned to successfully execute our business
strategy due to the following competitive strengths:
. Our pipeline assets are strategically located and have additional
capacity. Our primary crude oil pipeline transportation and gathering
assets are located in prolific oil producing regions and are connected,
directly or indirectly, with our terminalling and storage assets that
service major U.S. refinery and distribution markets where we have
strong business relationships. As a result, these assets are
strategically positioned to maximize the value of our crude oil by
transporting it to major trading locations and premium markets.
. The All American Pipeline is the only crude oil pipeline connecting
California to West Texas and has existing incremental operating
capacity of 65% of its designed capacity.
. The SJV Gathering System is one of the largest crude oil gathering
systems in the San Joaquin Valley of California, one of the most
prolific crude oil producing regions in the lower 48 states, and has
existing incremental operating capacity of approximately 30% of its
total 140,000 barrel per day capacity.
. Our West Texas Gathering System transports approximately 95,000
barrels per day of crude oil and has the capability to transport
approximately 190,000 barrels per day. It is connected to leases that
produce approximately 50,000 barrels per day and it provides us with
the ability to move crude oil between three of the primary trading
locations in West Texas. This system is connected to the All American
Pipeline at Wink and the Spraberry Pipeline System at Midland. In
addition, in connection with our merchant activities we expect to
increase the utilization of the 2.9 million barrels of storage
capacity located along the system.
. The Spraberry Pipeline System is an 800-mile gathering system that
extends throughout the Spraberry Trend, one of the largest producing
areas in West Texas. We are one of the largest gatherers in the
Spraberry Trend and our system gathers approximately 34,000 barrels
per day of crude oil.
In addition, because a major portion of the operating costs associated
with these pipeline systems are fixed, any increased utilization should
result in incremental gross margin.
. Our Cushing Terminal is strategically located, operationally flexible
and readily expandable. Completed in 1993, and expanded in 1999, the
Cushing Terminal is the most modern terminalling and storage facility at
the Cushing Interchange, incorporating state-of-the-art environmental
safeguards and operational enhancements designed to safely and
efficiently terminal, store, blend, and segregate large volumes and
multiple varieties of crude oil. The Cushing Terminal has the ability to
. sequentially store sweet and sour crude oil in the same tank without
compromising crude integrity;
. segregate up to 22 different varieties of crude oil;
. receive and deliver crude oil at the connecting pipelines' maximum
operating capacities; and
. operate with fewer employees than its competitors due to its high
level of automation.
Due to our ownership of a significant portion of the undeveloped land
within the Cushing Interchange and its large manifold and pumping
system, the Cushing Terminal can be readily expanded, should market
conditions warrant, to provide up to ten million barrels of tank
capacity.
. We possess specialized crude oil market knowledge. The marketing of
crude oil is complex and requires detailed current knowledge of crude
oil sources and end markets and a familiarity with a number of factors,
including grades of crude oil, individual refinery demand for specific
grades of crude oil, area market price structures for the different
grades of crude oil, location of customers, availability of
transportation facilities and timing and costs (including storage)
involved in delivering crude oil to the appropriate customer. We handle
over 50 different varieties and grades of domestic and foreign crude oil
and transport, terminal, gather and market an aggregate of approximately
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<PAGE>
850,000 barrels of crude oil per day. We believe our business
relationships with participants in all phases of the crude oil
distribution chain, from crude oil producers to refiners, as well as our
own industry expertise, provide us with a comprehensive understanding of
the U.S. crude oil markets. We believe that our specialized crude oil
market knowledge, in conjunction with our unique asset base, will enable
us to continue to exploit inefficiencies throughout the crude oil
distribution chain.
. Our business activities are counter-cyclically balanced. We believe that
the counter-cyclical nature of our terminalling and storage activities,
which typically prosper in contango crude oil markets, and our gathering
and marketing activities, which typically prosper in backward crude oil
markets, combined with the long-term nature of the contracts on our
pipeline systems, will have a stabilizing effect on our cash flow from
operations.
. We have the financial flexibility to pursue expansion and acquisition
opportunities. As of June 30, 1999, we had an aggregate of $45 million
of available borrowing capacity under our revolving credit facilities.
In addition, we believe we have additional debt capacity beyond that
available under our existing credit facilities. In combination with our
ability to issue new partnership units, we have significant resources to
finance strategic expansion and acquisition opportunities. These
opportunities may include the acquisition or expansion of crude oil
pipeline assets, gathering systems, terminalling and storage facilities,
marketing entities and other assets that we believe will contribute to
the successful execution of our business strategy. We routinely evaluate
acquisition and expansion opportunities and have made contact with
several owners of potentially attractive assets and businesses. However,
we currently have no commitments for material acquisitions or expansions
at this time.
. We have an experienced management team. Our senior management team has
an average of more than 20 years industry experience, with an average of
over 15 years with us or our predecessors and affiliates. We believe
optimal performance is achieved by creating and maintaining an
environment that rewards our employees for superior performance. In
order to incentivize our management and employees, we have adopted a
Long-Term Incentive Plan pursuant to which common units will be awarded
to employees of the General Partner in order to align their economic
interests with those of common unitholders. In addition, under our
Management Incentive Plan we pay cash bonuses to management personnel
based on our financial performance.
Crude Oil Pipeline Operations
We have presented below a description of our principal pipeline assets. All
of our pipeline systems are operated from one of two central control rooms with
SCADA computer systems designed to continuously monitor real time operational
data including measurement of crude oil quantities injected in and delivered
through the pipelines, product flow rates and pressure and temperature
variations. This monitoring and measurement technology provides us the ability
to efficiently batch differing crude oil types with varying characteristics
through the pipeline systems. The SCADA systems are designed to enhance leak
detection capabilities, sound automatic alarms in the event of operational
conditions outside of pre-established parameters and provide for remote-
controlled shut-down of pump stations on the pipeline systems. Pump stations,
storage facilities and meter measurement points along the pipeline systems are
linked by telephone, microwave or satellite communication systems for remote
monitoring and control, which reduces our requirement for full time site
personnel at most of these locations.
We perform scheduled maintenance on all of our pipeline systems and make
repairs and replacements when necessary or appropriate. We attempt to control
corrosion of the mainlines through the use of corrosion inhibiting chemicals
injected into the crude stream, external coatings and anode bed based or
impressed current cathodic protection systems. We monitor the structural
integrity of the large diameter pipelines through a program of periodic
internal inspections using electronic "smart pig" instruments. Maintenance
facilities containing equipment for pipe repairs, spare parts and trained
response personnel are strategically located along the pipelines and in
concentrated operating areas. We believe that all of our pipelines have been
constructed
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and are maintained in all material respects in accordance with applicable
federal, state and local laws and regulations, standards prescribed by the
American Petroleum Institute and accepted industry practice.
All American Pipeline
The 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 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 us.
The All American Pipeline is a heated pipeline system that extends
approximately 10 miles from Exxon's onshore facilities at Las Flores on the
California coast to Plains Resources' onshore facilities at Gaviota, California
(24 inch diameter pipe) and continues from Gaviota approximately 130 miles to
our station in Emidio, California (30-inch pipe). Between Gaviota and our
Emidio Station, the All American Pipeline interconnects with our SJV Gathering
System as well as various third party intrastate pipelines, including the
Unocap Pipeline System, Pacific Pipeline, Line 63 and a pipeline owned by EOTT
Energy Partners, L.P. Activities conducted on this portion of the pipeline
represent the majority of the transportation service provided for owners of the
Santa Ynez and Point Arguello fields and a significant portion of our
California margin activities. For the six months ended June 30, 1999, these
activities accounted for approximately 85% of total gross margin from pipeline
activities.
From Emidio, the All American Pipeline extends approximately 1,090 miles
through Arizona and New Mexico to West Texas (30-inch diameter pipe) where it
interconnects with other pipelines, including our West Texas Gathering System.
Some of 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. In addition to
facilitating transportation, we believe that such tankage provides arbitrage
opportunities for us. Unlike many common carrier pipelines, we own the
approximately 5.0 million barrels of crude oil that is used to maintain the All
American Pipeline's linefill requirements. Most of the 5.0 million barrels of
crude oil linefill is located in the segment of the pipeline east of Emidio.
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.
System Supply. The All American Pipeline transports several different types
of crude oil, including:
. Outer Continental Shelf crude oil received at the onshore facilities of
the Santa Ynez field at Las Flores, California and the onshore
facilities of the Point Arguello field located at Gaviota, California,
and
. Elk Hills, Midway Sunset, Belridge Light, Belridge Heavy and Cymeric
crude oil, received at Pentland, California from a connection with the
SJV Gathering System. The crude oil received from the SJV Gathering
System is typically blended and delivered to customer specification.
Exxon, which owns all of the Santa Ynez production, and Plains Resources,
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
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June 30, 1999, 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 us have no other means of transporting their
production and, therefore, ship their volumes on the All American Pipeline at
the posted tariffs. During the first six months of 1999, approximately $15
million, or 23%, of our pro forma gross margin was attributable to the Santa
Ynez field and approximately $6 million, or 9%, was attributable to the Point
Arguello field. Transportation of volumes from the Point Arguello field on the
All American Pipeline commenced in 1991 and from the Santa Ynez field in 1994.
The table below sets forth the historical volumes received from both of
these fields.
<TABLE>
<CAPTION>
Six
Months
Ended
Year Ended December 31, June 30,
--------------------------------------- ---------
1991 1992 1993 1994 1995 1996 1997 1998 1998 1999
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes
received from:
Point Arguello (at
Gaviota)................. 29 47 63 73 60 41 30 26 28 22
Santa Ynez (at Las
Flores).................. - - - 34 92 95 85 68 69 61
--- --- --- --- --- --- --- --- --- ---
Total................... 29 47 63 107 152 136 115 94 97 83
=== === === === === === === === === ===
</TABLE>
In July 1999, a wholly owned subsidiary of Plains Resources acquired Chevron
USA's 26% working interest in the Point Arguello Field and, subject to
regulatory approval, will be the operator of record. All of the volumes
attributable to Plains Resources' interests are committed for transportation on
the All American Pipeline and will be subject to our Marketing Agreement with
Plains Resources. Plains Resources believes that opportunities exist to
minimize production decline and, barring operational or economic disruptions,
to offset production decline or increase production. We anticipate that average
daily production received from the Santa Ynez and Point Arguello fields for
1999 and 2000 will generally approximate 75,000 to 80,000 barrels although we
can provide no assurance in that regard.
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 our
control, including
. the economic feasibility of developing the reserves;
. the economic feasibility of connecting such reserves to the All American
Pipeline; and
. the ability of the owners of such reserves to obtain the necessary
governmental approvals to develop such reserves.
The owners of these reserves have filed development plans with the MMS. The MMS
has stated that it will respond to these development plans in the fourth
quarter of this year. We cannot assure you 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. We also cannot assure you that, if such reserves were
developed, a competing pipeline will 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
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<PAGE>
majority of the votes cast by the voters of the affected 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 Energy Partners, L.P. and Pacific Pipeline System L.L.C. The
San Joaquin Valley is one of the most prolific oil producing regions in the
continental United States, producing approximately 566,000 barrels per day of
crude oil during the first four months of 1999 that accounted for approximately
66% of total California production and 12% 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.
<TABLE>
<CAPTION>
Four
Months
Ended
Year Ended December 31, April 30,
-------------------------------------------- ---------
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ---- ---- ---- ---- ---------
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes:
San Joaquin Valley
production(1)........ 629 634 609 588 578 569 579 584 592 566
Total California
production (excluding
OCS volumes)......... 879 875 835 803 784 764 772 781 781 739
</TABLE>
- --------
(1) Includes production from California Division of Oil and Gas District IV.
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 oil price environment that existed throughout 1998
and the first four months of 1999. Although activity in the area has increased
along with the increase in oil prices in mid-1999, we cannot assure you that
the recent trend of production decline will not continue.
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 Emidio. Deliveries at Mojave were
discontinued in the second quarter of 1999, and volumes previously delivered to
Mojave are delivered to Emidio. Crude oil transported to West Texas is
primarily a blended stream referred to as West Coast Heavy and is delivered to
third-party pipelines at Wink and McCamey, Texas. At Wink, we blend West Coast
Heavy crude 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 or our West
Texas Gathering System. At McCamey, West Coast Heavy is delivered to a third-
party pipeline that supplies refiners on the Gulf Coast.
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<PAGE>
The following table sets forth All American Pipeline average deliveries per
day within and outside California.
<TABLE>
<CAPTION>
Six
Months
Ended
Year Ended December 31, June 30,
------------------------ ---------
1994 1995 1996 1997 1998 1998 1999
---- ---- ---- ---- ---- ---- ----
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes delivered to:
California
Sisquoc................................. 21 11 17 21 24 23 29
Pentland................................ 56 65 71 74 69 72 54
Mojave.................................. - - 6 32 22 22 14
Emidio.................................. - - - - - - 9
--- --- --- --- --- --- ---
Total California...................... 77 76 94 127 115 117 106
Texas..................................... 108 141 113 68 59 61 62
--- --- --- --- --- --- ---
Total................................. 185 217 207 195 174 178 168
=== === === === === === ===
</TABLE>
SJV Gathering System
The SJV Gathering System is a proprietary pipeline system that only
transports crude oil purchased by us. 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
that crude oil along the pipeline system in order to deliver various blends
into the All American Pipeline.
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 can be used to facilitate movements
along the system as well as to support our other activities.
The SJV Gathering System is supplied with the crude oil production primarily
from major oil companies' equity production from the South Belridge, Cymeric,
Midway Sunset, Elk Hills and Lost Hills fields. The table below sets forth the
historical volumes received into the SJV Gathering System.
<TABLE>
<CAPTION>
Six
Months
Ended
Year Ended December 31, June 30,
------------------------ ---------
1994 1995 1996 1997 1998 1998 1999
---- ---- ---- ---- ---- ---- ----
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Total average daily volumes.................. 54 50 67 91 85 91 99
</TABLE>
West Texas Gathering System
We purchased the West Texas Gathering System from Chevron Pipe Line Company
in July 1999 for approximately $36 million. The West Texas Gathering System is
a common carrier crude oil pipeline system located in the heart of the Permian
Basin producing area. The West Texas Gathering System has lease gathering
facilities in Crane, Ector, Upton, Ward and Winkler counties. In aggregate,
these counties have produced on average in excess of 150,000 barrels per day of
crude oil over the last four years. The West Texas Gathering System was
originally built by Gulf Oil Corporation in the late 1920's, expanded during
the late 1950's and updated during the mid 1990's. The West Texas Gathering
System provides us with considerable flexibility, as major segments are bi-
directional and allow us to move crude oil between three of the major trading
locations in West Texas.
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<PAGE>
Lease volumes gathered into the system are approximately 50,000 barrels per
day. Chevron USA has agreed to transport its equity crude oil production from
fields connected to the West Texas Gathering System on the system for the next
12 years (currently representing approximately 26,000 barrels per day, or 52%
of total system gathering volumes and 27% of the total system volumes). Other
large producers connected to the gathering system include Burlington, Devon,
Anadarko, Altura, Bass, and Fina. Volumes from connecting carriers, including
Exxon, Phillips and Unocal, average approximately 45,000 barrels per day. Our
West Texas Gathering System has the capability to transport approximately
190,000 barrels per day. At the time of the acquistion, truck injection
stations were limited and provided less than 1,000 barrels per day. We have
installed four truck injection stations on the West Texas Gathering System and
will install an additional five stations by the end of October. Our trucks are
used to pick up crude oil produced in the areas adjacent to the West Texas
Gathering System and deliver these volumes into the pipeline. These additional
injection stations will allow us to reduce the distance of our truck hauls in
this area, increase the utilization of our pipeline assets and reduce our
operating costs. We expect to increase volumes received from truck injection
stations to 10,000 barrels per day by the fourth quarter of 1999. The West
Texas Gathering System also includes approximately 2.9 million barrels of tank
capacity located along the pipeline system, which has been underutilized.
In the past, Chevron has used the West Texas Gathering System principally to
move its equity production to its refinery in El Paso, Texas, and not as a
source of third-party revenues. As a result, we believe that the system has
been significantly underutilized. We intend to expand the use of the West Texas
Gathering System by capitalizing on its strategic location and integrating it
with our lease gathering efforts and other operations in West Texas and the All
American Pipeline.
Spraberry Pipeline System
The Spraberry Pipeline System, acquired in the Scurlock acquisition, is a
proprietary pipeline system that gathers crude oil from the Spraberry Trend of
West Texas and transports it to Midland, Texas, where it interconnects with the
West Texas Gathering System and other pipelines. The Spraberry Pipeline System
consists of approximately 800 miles of pipe of varying diameter, and has a
throughput capacity of approximately 50,000 barrels of crude oil per day. The
Spraberry Trend is one of the largest producing areas in West Texas and we are
one of the largest gatherers in the Spraberry Trend. The Spraberry Pipeline
System gathers approximately 34,000 barrels per day of crude oil. Large
suppliers to the Spraberry Pipeline System include Lantern Petroleum and
Pioneer Natural Resources. The Spraberry Pipeline System also includes
approximately 173,000 barrels of tank capacity located along the pipeline.
Sabine Pass Pipeline System
The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a
common carrier crude oil pipeline system. The primary purpose of the Sabine
Pass Pipeline System is to gather crude oil from onshore facilities of offshore
production near Johnson Bayou, Louisiana, and deliver it to tankage and barge
loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System
consists of approximately 34 miles of pipe ranging from 4 to 6 inches in
diameter and has a throughput capacity of approximately 26,400 barrels of
Louisiana light sweet crude oil per day. For the six months ended June 30,
1999, the system transported approximately 15,500 barrels of crude oil per day.
The Sabine Pass Pipeline System also includes 245,000 barrels of tank capacity
located along the pipeline.
Ferriday Pipeline System
The Ferriday Pipeline System, acquired in the Scurlock acquisition, is a
common carrier crude oil pipeline system which is located in East Louisiana and
West Mississippi. The Ferriday Pipeline System consists of approximately 600
miles of pipe ranging from 2 inches to 12 inches in diameter. The Ferriday
Pipeline System delivers approximately 8,000 barrels per day of crude oil to
third-party pipelines that supply refiners in the Midwest. The Ferriday
Pipeline System also includes approximately 348,000 barrels of tank capacity
located along the pipeline.
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<PAGE>
On August 3, 1999, we received approval of our application to construct an
8-inch pipeline underneath the Mississippi River that will enable us to connect
our Ferriday Pipeline System in western Mississippi with the portion of the
system located in eastern Louisiana. When completed, this connection will
provide us with access to additional markets and enhance our ability to service
our pipeline customers and take advantage of additional high margin merchant
activities.
East Texas Pipeline System
The East Texas Pipeline System, acquired in the Scurlock acquisition, is a
proprietary crude oil pipeline system that is used to gather approximately
10,000 barrels per day of lease connected crude oil in East Texas and transport
approximately 22,000 barrels per day of crude oil to Crown Central's refinery
in Longview, Texas. The deliveries to Crown Central are subject to a five-year
throughput and deficiency agreement, which extends through 2004. The East Texas
Pipeline System also includes approximately 221,000 barrels of tank capacity
located along the pipeline.
Illinois Basin Pipeline System
The Illinois Basin Pipeline System, acquired in conjunction with the
Scurlock acquisition, consists of common carrier pipeline and gathering systems
and truck injection facilities in southern Illinois. The Illinois Basin
Pipeline System consists of approximately 170 miles of pipe of varying diameter
and delivers approximately 8,000 barrels per day of crude oil to third-party
pipelines that supply refiners in the Midwest. Approximately 3,500 barrels per
day of the supply on this system is from fields operated by Plains Resources.
Terminalling and Storage Activities and Gathering and Marketing Activities
Terminalling and Storage Activities
We own approximately 9.7 million barrels of terminalling and storage assets,
including tankage associated with our pipeline and gathering systems. Our
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 our merchant activities. Storage fees are generated when we
lease tank capacity to third parties. Terminalling fees, also referred to as
throughput fees, are generated when we receive crude oil from one connecting
pipeline and redeliver such crude oil to another connecting carrier in volumes
that allow the refinery to receive its crude oil on a ratable basis throughout
a delivery period. Both terminalling and storage fees are generally earned
from:
. refiners and gatherers that segregate or custom blend crudes for
refining feedstocks;
. pipeline operators, refiners or traders that need segregated tankage for
foreign cargoes;
. traders who make or take delivery under NYMEX contracts; and
. producers and resellers that seek to increase their marketing
alternatives.
The tankage that is used to support our arbitrage activities positions us to
capture margins in a contango market or when the market switches from contango
to backwardation.
The most significant asset is our Cushing Terminal which was constructed in
1993, and expanded in 1999, to capitalize on the crude oil supply and demand
imbalance in the Midwest. The imbalance was caused by the continued decline of
regional production supplies, increasing imports and an inadequate pipeline and
terminal infrastructure. The Cushing Terminal is also used to support and
enhance the margins associated with our merchant activities relating to our
lease gathering and bulk trading activities.
The Cushing Terminal has a total storage capacity of approximately 3.1
million barrels, including the approximate 1.1 million barrel expansion project
completed in mid-1999. The Cushing Terminal is comprised of fourteen 100,000
barrel tanks, four 150,000 barrel tanks and four 270,000 barrel tanks which are
used to
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<PAGE>
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.
The Cushing Terminal is a state-of-the-art facility designed to serve the
needs of refiners in the Midwest. In order to service an expected increase in
the volumes as well as the varieties of foreign and domestic crude oil
projected to be transported through the Cushing Interchange, we incorporated
certain attributes into the design of the Cushing Terminal including:
. multiple, smaller tanks to facilitate simultaneous handling of multiple
crude varieties in accordance with normal pipeline batch sizes;
. dual header systems connecting each tank to the main manifold system to
facilitate efficient switching between crude grades with minimal
contamination;
. bottom drawn sumps that enable each tank to be efficiently drained down
to minimal remaining volumes to minimize crude contamination and
maintain crude integrity during changes of service;
. mixer(s) on each tank to facilitate blending crude grades to refinery
specifications; and
. a manifold and pump system that allows for receipts and deliveries with
connecting carriers at their maximum operating capacity.
As a result of incorporating these attributes into the design of the Cushing
Terminal, we believe we are favorably positioned to serve the needs of Midwest
refiners to handle an increase in varieties of crude transported through the
Cushing Interchange.
The Cushing Terminal also incorporates numerous environmental and
operational safeguards. We believe that our terminal is the only one at the
Cushing Interchange in which each tank has a secondary liner (the equivalent of
double bottoms), leak detection devices and secondary seals. The Cushing
Terminal is the only terminal at the Cushing Interchange equipped with
aboveground pipelines. Like the pipeline systems we operate, the Cushing
Terminal is operated by a 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 double seal floating roof that minimizes air
emissions and prevents the possible accumulation of potentially flammable gases
between fluid levels and the roof of the tank; and a foam dispersal system
that, in the event of a fire, is fed by a fully-automated fire water
distribution network.
The Cushing Interchange is the largest wet barrel trading hub in the U.S.
and the delivery point for crude oil futures contracts traded on the NYMEX. The
Cushing Terminal has been designated by the NYMEX as an approved delivery
location for crude oil delivered under the NYMEX light sweet crude oil futures
contract. As a NYMEX delivery point and a cash market hub, the Cushing
Interchange serves as a primary source of refinery feedstock for the Midwest
refiners and plays an integral role in establishing and maintaining markets for
many varieties of foreign and domestic crude oil.
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The following illustration details the major pipeline systems and terminals
that deliver crude oil to, or can receive crude oil from, the Cushing
Terminal.
[GRAPHIC ILLUSTRATING THE MAJOR PIPELINE SYSTEMS DELIVERING CRUDE OIL TO OR
RECEIVING CRUDE OIL FROM THE CUSHING TERMINAL APPEARS HERE]
The following table outlines our terminal locations, capacities, tanks and
modes of receipt and deliveries:
<TABLE>
<CAPTION>
Shell Number Mode of
Facility Capacity of Tanks Mode of Receipt Delivery
-------- --------- -------- --------------- --------
(Barrels)
<S> <C> <C> <C> <C>
Cushing, Oklahoma....... 3,080,000 22 Truck/Pipeline Pipeline
Ingleside, Texas........ 360,000 11 Truck/Barge Truck/Barge
Venice, Louisiana....... 300,000 3 Truck/Barge/Pipeline Barge/Pipeline
St. Gabriel, Louisiana.. 100,000 3 Truck/Barge Barge
Abbeville, Louisiana.... 90,000 2 Truck/Barge Barge
LaGrange, Texas......... 80,000 1 Truck Pipeline
Larose, Louisiana....... 76,000 2 Truck/Barge Barge
Grand Chenier,
Louisiana.............. 53,000 3 Truck/Pipeline Barge
Charenton, Louisiana.... 44,000 1 Truck/Barge Barge
Point Comfort, Texas.... 30,000 2 Truck Barge
--------- ---
Total(1)............ 4,213,000 50
========= ===
</TABLE>
- --------
(1) Does not include approximately 5.5 million barrels of tankage associated
with our pipeline and gathering systems.
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The following table sets forth the throughput volumes for our terminalling
and storage operations, and quantity of tankage leased to third parties from
1994 through the six months ended June 30, 1999.
<TABLE>
<CAPTION>
Six Months
Ended
Year Ended December 31, June 30,
------------------------- ----------
1994 1995 1996 1997 1998 1998 1999
---- ---- ---- ---- ----- ---- -----
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Throughput Volumes (average daily
volumes):
Cushing, Oklahoma...................... 29 43 56 69 69 64 68
Ingleside, Texas....................... -- -- 3 8 11 11 11
--- --- --- --- ----- --- -----
Total................................ 29 43 59 77 80 75 79
=== === === === ===== === =====
Storage Leased to Third Parties (average
monthly volumes):
Cushing, Oklahoma...................... 464 208 203 414 890 675 1,778
Ingleside, Texas....................... -- -- 211 254 260 260 243
--- --- --- --- ----- --- -----
Total................................ 464 208 414 668 1,150 935 2,021
=== === === === ===== === =====
</TABLE>
Gathering and Marketing Activities
Our gathering and marketing activities are conducted in 23 states; however,
the vast majority of those activities are in Texas, Louisiana, California,
Illinois and the Gulf of Mexico. These activities include:
. purchasing crude oil from producers at the wellhead and in bulk from
aggregators at major pipeline interconnects and trading locations;
. transporting such crude oil on our own proprietary gathering assets or
assets owned and operated by third parties when necessary or cost
effective;
. 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
. marketing crude oil to refiners or other resellers.
We purchase crude oil from many independent producers and believe that we
have established broad-based relationships with crude oil producers in our
areas of operations. For the six months ended June 30, 1999, we purchased
approximately 186,000 barrels per day of crude oil directly at the wellhead
from more than 2,300 producers from approximately 16,500 leases. We purchase
crude oil from producers under contracts that range in term from a thirty-day
evergreen to three 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 our lease gathering
and bulk purchases from 1995 through the six months ended June 30, 1999.
<TABLE>
<CAPTION>
Six
Months
Year Ended December Ended
31, June 30,
------------------- ---------
1995 1996 1997 1998 1998 1999
---- ---- ---- ---- ---- ----
(barrels in thousands)
<S> <C> <C> <C> <C> <C> <C>
Lease Gathering(1)................................ 46 59 71 88 82 186
Bulk Purchases.................................... 10 32 49 95 102 116
--- --- --- --- --- ---
Total volumes................................... 56 91 120 183 184 302
=== === === === === ===
</TABLE>
- --------
(1) Includes volumes from Scurlock Permian since May 1, 1999.
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Crude Oil Purchases. In a typical producer's operation, crude oil flows from
the wellhead to a separator where the petroleum gases are removed. After
separation, the crude oil is treated to remove water, sand and other
contaminants and is then moved into the producer's on-site storage tanks. When
the tank is full, the producer contacts our field personnel to purchase and
transport the crude oil to market. We utilize our truck fleet and gathering
pipelines and third-party pipelines, trucks and barges to transport the crude
oil to market. We own or lease approximately 290 trucks, 320 tractor-trailers
and 240 injection stations.
Pursuant to the Marketing Agreement, we are the exclusive marketer/purchaser
for all of Plains Resources' equity crude oil production. The Marketing
Agreement provides that we will purchase for resale at market prices all of
Plains Resources' crude oil production for which we charge a fee of $0.20 per
barrel. This fee will be adjusted every three years based upon then existing
market conditions. The Marketing Agreement will terminate upon a "change of
control" of Plains Resources or the general partner. Revenues generated under
the Marketing Agreement for the six months ended June 30, 1999 were
approximately $674,000. For the first six months of 1999, Plains Resources
produced approximately 18,600 barrels per day subject to the Marketing
Agreement. Plains Resources owns an approximate 100% working interest in each
of its fields, except for Point Arguello in which it owns an approximate 26%
working interest.
Bulk Purchases. In addition to purchasing crude oil at the wellhead from
producers, we purchase crude oil in bulk at major pipeline terminal points.
This production is transported from the wellhead to the pipeline by major oil
companies, large independent producers or other gathering and marketing
companies. We purchase crude oil in bulk when we believe additional
opportunities exist to realize margins further downstream in the crude oil
distribution chain. The opportunities to earn additional margins vary over time
with changing market conditions. Accordingly, the margins associated with our
bulk purchases will fluctuate from period to period. Our bulk purchasing
activities are concentrated in California, Texas, Louisiana and at the Cushing
Interchange.
Crude Oil Sales. The marketing of crude oil is complex and requires detailed
current knowledge of crude oil sources and end markets and a familiarity with a
number of factors including grades of crude oil, individual refinery demand for
specific grades of crude oil, area market price structures for the different
grades of crude oil, location of customers, availability of transportation
facilities and timing and costs (including storage) involved in delivering
crude oil to the appropriate customer. We sell our crude oil to major
integrated oil companies, independent refiners and other resellers in various
types of sale and exchange transactions, at market prices for terms ranging
from one month to three years.
As we purchase crude oil, we establish a margin by selling crude oil for
physical delivery to third party users, such as independent refiners or major
oil companies, or by entering into a future delivery obligation with respect to
futures contracts on the NYMEX. Through these transactions, we seek to maintain
a position that is substantially balanced between crude oil purchases and sales
and future delivery obligations. We from time to time enter into fixed price
delivery contracts, floating price collar arrangements, financial swaps and oil
futures contracts as hedging devices. Our policy is generally to purchase only
crude oil for which we have a market and to structure our sales contracts so
that crude oil price fluctuations do not materially affect the gross margin
which we receive. We do not acquire and hold crude oil, futures contracts or
other derivative products for the purpose of speculating on crude oil price
changes that might expose us to indeterminable losses.
Risk management strategies, including those involving price hedges using
NYMEX futures contracts, have become increasingly important in creating and
maintaining margins. Such hedging techniques require significant resources
dedicated to managing futures positions. We are able to monitor crude oil
volumes, grades, locations and delivery schedules and to coordinate marketing
and exchange opportunities, as well as NYMEX hedging positions. This
coordination ensures that our NYMEX hedging activities are successfully
implemented.
Crude Oil Exchanges. We pursue exchange opportunities to enhance margins
throughout the gathering and marketing process. When opportunities arise to
increase our margin or to acquire a grade of crude oil that more nearly matches
our delivery requirement or the preferences of our refinery customers, we
exchange physical
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crude oil with third parties. These exchanges are effected through contracts
called exchange or buy-sell agreements. Through an exchange agreement, we agree
to buy crude oil that differs in terms of geographic location, grade of crude
oil or delivery schedule from crude oil we have available for sale. Generally,
we enter into exchanges to acquire crude oil at locations that are closer to
our end markets, thereby reducing transportation costs and increasing our
margin. We also exchange our crude oil to be delivered at an earlier or later
date, if the exchange is expected to result in a higher margin net of storage
costs, and enter into exchanges based on the grade of crude oil, which includes
such factors as sulfur content and specific gravity, in order to meet the
quality specifications of our delivery contracts.
Producer Services. Crude oil purchasers who buy from producers compete on
the basis of competitive prices and highly responsive services. Through our
team of crude oil purchasing representatives, we maintain ongoing relationships
with more than 2,300 producers. We believe that our ability to offer high-
quality field and administrative services to producers is a key factor in our
ability to maintain volumes of purchased crude oil and to obtain new volumes.
High-quality field services include efficient gathering capabilities,
availability of trucks, willingness to construct gathering pipelines where
economically justified, timely pickup of crude oil from tank batteries at the
lease or production point, accurate measurement of crude oil volumes received,
avoidance of spills and effective management of pipeline deliveries. Accounting
and other administrative services include securing division orders (statements
from interest owners affirming the division of ownership in crude oil purchased
by us), providing statements of the crude oil purchased each month, disbursing
production proceeds to interest owners and calculation and payment of ad
valorem and production taxes on behalf of interest owners. In order to compete
effectively, we must maintain records of title and division order interests in
an accurate and timely manner for purposes of making prompt and correct payment
of crude oil production proceeds, together with the correct payment of all
severance and production taxes associated with such proceeds.
Credit. Our merchant activities involve the purchase of crude oil for resale
and require significant extensions of credit by our suppliers of crude oil. In
order to assure our ability to perform our obligations under crude oil purchase
agreements, various credit arrangements are negotiated with our crude oil
suppliers. Such arrangements include open lines of credit directly with us and
standby letters of credit issued under our letter of credit facility. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--The Partnership--Capital Resources, Liquidity and Financial
Condition."
When we market crude oil, we must determine the amount, if any, of the line
of credit to be extended to any given customer. If we determine that a customer
should receive a credit line, we must then decide on the amount of credit that
should be extended. Since our typical sales transactions can involve tens of
thousands of barrels of crude oil, the risk of nonpayment and nonperformance by
customers is a major consideration in our business. We believe our sales are
made to creditworthy entities or entities with adequate credit support.
Credit review and analysis are also integral to our leasehold purchases.
Payment for all or substantially all of the monthly leasehold production is
sometimes made to the operator of the lease. The operator, in turn, is
responsible for the correct payment and distribution of such production
proceeds to the proper parties. In these situations, we must determine whether
the operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend us in the event any third party
should bring a protest, action or complaint in connection with the ultimate
distribution of production proceeds by the operator.
Customers
Sempra Energy Trading Corporation and Koch Oil Company accounted for 30% and
17%, respectively, of the combined 1998 revenues of us and our predecessor. No
other individual customer accounted for greater than 10% of our revenues in
1998.
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.
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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, we expect that certain volumes currently transported on the
All American Pipeline may be redirected to Los Angeles on such pipeline.
Competition among pipelines is based primarily on transportation charges,
access to producing areas and demand for the crude oil by end users. We believe
that high capital requirements, environmental considerations and the difficulty
in acquiring rights of way and related permits make it unlikely that a
competing pipeline system comparable in size and scope to our pipeline systems,
particularly the All American Pipeline, will be built in the foreseeable
future.
We face intense competition in our terminalling and storage activities and
gathering and marketing activities. Our competitors include other crude oil
pipelines, the major integrated oil companies, their marketing affiliates and
independent gatherers, brokers and marketers of widely varying sizes, financial
resources and experience. Some of these competitors have capital resources many
times greater than ours and control substantially greater supplies of crude
oil.
Regulation
Our operations are subject to extensive regulation. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil industry and its individual
participants. The failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the oil industry increases
our cost of doing business and, consequently, affects our profitability.
However, we do not believe that we are affected in a significantly different
manner by these regulations than are our competitors. Due to the myriad of
complex federal and state statutes and regulations which may affect us,
directly or indirectly, you should not rely on the following discussion of
certain statutes and regulations as an exhaustive review of all regulatory
considerations affecting our operations.
Pipeline Regulation
Our pipelines are subject to regulation by the Department of Transportation
under the Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA")
relating to the design, installation, testing, construction, operation,
replacement and management of pipeline facilities. The HLPSA requires us and
other pipeline operators to comply with regulations issued pursuant to HLPSA,
to permit access to and allow copying of records and to make certain reports
and provide information as required by the Secretary of Transportation.
The Pipeline Safety Act of 1992 amends the HLPSA in several important
respects. It requires the Research and Special Programs Administration of the
Department of Transportation to consider environmental impacts, as well as its
traditional public safety mandate, when developing pipeline safety regulations.
In addition, the Pipeline Safety Act mandates the establishment by the
Department of Transportation of pipeline operator qualification rules requiring
minimum training requirements for operators, and requires that pipeline
operators provide maps and records to the Research and Special Programs
Administration. It also authorizes the Research and Special Programs
Administration to require that pipelines be modified to accommodate internal
inspection devices, to mandate the installation of emergency flow restricting
devices for pipelines in populated or sensitive areas and to order other
changes to the operation and maintenance of petroleum pipelines. We believe
that our pipeline operations are in substantial compliance with applicable
HLPSA and Pipeline Safety Act requirements. Nevertheless, we could incur
significant expenses in the future if additional safety measures are required
or if safety standards are raised and exceed the current pipeline control
system capabilities.
States are largely preempted by federal law from regulating pipeline safety
but may assume responsibility for enforcing federal intrastate pipeline
regulations and inspection of intrastate pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety. We do
not anticipate any significant problems in complying with applicable state laws
and regulations in those states in which we operate.
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Tariff Regulation
In October 1992 Congress passed the Energy Policy Act of 1992. The Energy
Policy Act deemed petroleum pipeline rates in effect for the 365-day period
ending on the date of enactment of the Energy Policy Act or that were in effect
on the 365th day preceding enactment and had not been subject to complaint,
protest or investigation during the 365-day period to be just and reasonable
under the Interstate Commerce Act. The Energy Policy Act also provides that
complaints against such rates may only be filed under the following limited
circumstances:
. a substantial change has occurred since enactment in either the
economic circumstances or the nature of the services which were a basis
for the rate;
. the complainant was contractually barred from challenging the rate
prior to enactment; or
. a provision of the tariff is unduly discriminatory or preferential.
The Energy Policy Act further required the FERC to issue rules establishing
a simplified and generally applicable ratemaking methodology for petroleum
pipelines, and to streamline procedures in petroleum pipeline proceedings. On
October 22, 1993, the FERC responded to the Energy Policy Act directive by
issuing Order No. 561, which adopts a new indexing rate methodology for
petroleum pipelines. Under the new regulations, which were effective January 1,
1995, petroleum pipelines are able to change their rates within prescribed
ceiling levels that are tied to the Producer Price Index for Finished Goods,
minus one percent. Rate increases made pursuant to the index will be subject to
protest, but such protests must show that the portion of the rate increase
resulting from application of the index is substantially in excess of the
pipeline's increase in costs. The new indexing methodology can be applied to
any existing rate, even if the rate is under investigation. If such rate is
subsequently adjusted, the ceiling level established under the index must be
likewise adjusted.
In Order No. 561, the FERC said that as a general rule pipelines must
utilize the indexing methodology to change their rates. The FERC indicated,
however, that it was retaining cost-of-service ratemaking, market-based rates,
and settlements as alternatives to the indexing approach. A pipeline can follow
a cost-of-service approach when seeking to increase its rates above index
levels for uncontrollable circumstances. A pipeline can seek to charge market-
based rates if it can establish that it lacks market power. In addition, a
pipeline can establish rates pursuant to settlement if agreed upon by all
current shippers. Initial rates for new services can be established through a
cost-of-service proceeding or through an uncontested agreement between the
pipeline and 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 proceeding involving Lakehead Pipe Line Company, Limited Partnership
(Opinion No. 397), FERC concluded that there should not be a corporate income
tax allowance built into a petroleum pipeline's rates to reflect income
attributable to noncorporate partners since noncorporate partners, unlike
corporate partners, do not pay a corporate income tax. This result comports
with the principle that, although a regulated entity is entitled to an
allowance to cover its incurred costs, including income taxes, there should not
be an element included in the cost of service to cover costs not incurred.
Opinion No. 397 was affirmed on rehearing in May 1996. Appeals of the Lakehead
opinions were taken, but the parties to the Lakehead proceeding subsequently
settled the case, with the result that appellate review of the tax and other
issues never took place.
A proceeding is also pending on rehearing at the FERC involving another
publicly traded limited partnership engaged in the common carrier
transportation of crude oil (the "Santa Fe Proceeding") in which the FERC could
further limit its current position related to the tax allowance permitted in
the rates of publicly traded partnerships, as well as possibly alter the FERC's
current application of the FERC oil pipeline ratemaking methodology. On January
13, 1999, the FERC issued Opinion No. 435 in the Santa Fe Proceeding,
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which, among other things, affirmed Opinion No. 397's determination that there
should not be a corporate income tax allowance built into a petroleum
pipeline's rates to reflect income attributable to noncorporate partners.
Requests for rehearing of Opinion No. 435 are pending before the FERC.
Petitions for review of Opinion No. 435 are before the D.C. Circuit Court of
Appeals, but are being held in abeyance pending FERC action on the rehearing
requests.
The FERC generally has not investigated rates, such as those currently
charged by us, which have been mutually agreed to by the pipeline and the
shippers or which are significantly below cost of service rates that might
otherwise be justified by the pipeline under the FERC's cost-based ratemaking
methods. Substantially all of our gross margins on transportation are produced
by rates that are either grandfathered or set by agreement of the parties. 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, we believe that the rates
now in effect can be sustained, although no assurance can be given that the
rates currently charged would ultimately be upheld if challenged. In addition,
we do not believe that an adverse determination on the tax allowance issue in
the Santa Fe Proceeding would have a detrimental impact upon our current rates.
Trucking Regulation
We operate a fleet of trucks to transport crude oil and oilfield materials
as a private, contract and common carrier. We are licensed to perform both
intrastate and interstate motor carrier services. As a motor carrier, we are
subject to certain safety regulations issued by the Department of
Transportation. The trucking regulations cover, among other things, driver
operations, keeping of log books, truck manifest preparations, the placement of
safety placards on the trucks and trailer vehicles, drug and alcohol testing,
safety of operation and equipment, and many other aspects of truck operations.
We are also subject to OSHA with respect to our trucking operations.
Environmental Regulation
General
Various federal, state and local laws and regulations governing the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, affect our operations and costs. In particular,
our activities in connection with storage and transportation of crude oil and
other liquid hydrocarbons and our use of facilities for treating, processing or
otherwise handling hydrocarbons and wastes are subject to stringent
environmental regulation. As with the industry generally, compliance with
existing and anticipated regulations increases our overall cost of business.
Areas affected include capital costs to construct, maintain and upgrade
equipment and facilities. While these regulations affect our capital
expenditures and earnings, we believe that these regulations do not affect our
competitive position in that the operations of our competitors that comply with
such regulations are similarly affected. Environmental regulations have
historically been subject to frequent change by regulatory authorities, and we
are unable to predict the ongoing cost to us of complying with these laws and
regulations or the future impact of such regulations on our operations.
Violation of federal or state environmental laws, regulations and permits can
result in the imposition of significant civil and criminal penalties,
injunctions and construction bans or delays. A discharge of hydrocarbons or
hazardous substances into the environment could, to the extent such event is
not insured, subject us to substantial expense, including both the cost to
comply with applicable regulations and claims by neighboring landowners and
other third parties for personal injury and property damage.
Water
The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of
the Federal Water Pollution Control Act of 1972 ("FWPCA") and other statutes as
they pertain to prevention and response to oil
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spills. The OPA subjects owners of facilities to strict, joint and potentially
unlimited liability for removal costs and certain other consequences of an oil
spill, where such spill is into navigable waters, along shorelines or in the
exclusive economic zone of the U.S. In the event of an oil spill into navigable
waters, substantial liabilities could be imposed upon us. States in which we
operate have also enacted similar laws. Regulations are currently being
developed under OPA and state laws that may also impose additional regulatory
burdens on our operations.
The FWPCA imposes restrictions and strict controls regarding the discharge
of pollutants into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA imposes substantial
potential liability for the costs of removal, remediation and damages. We
believe that compliance with existing permits and compliance with foreseeable
new permit requirements will not have a material adverse effect on our
financial condition or results of operations.
Some states maintain groundwater protection programs that require permits
for discharges or operations that may impact groundwater conditions. We believe
that we are in substantial compliance with these state requirements.
Air Emissions
Our operations are subject to the Federal Clean Air Act and comparable state
and local statutes. We believe that our operations are in substantial
compliance with these statutes in all states in which we operate.
Amendments to the Federal Clean Air Act enacted in late 1990 (the "1990
Federal Clean Air Act Amendments") require or will require most industrial
operations in the U.S. to incur capital expenditures in order to meet air
emission control standards developed by the Environmental Protection Agency
(the "EPA") and state environmental agencies. In addition, the 1990 Federal
Clean Air Act Amendments include a new operating permit for major sources
("Title V permits"), which applies to some of our facilities. Although we can
give no assurances, we believe implementation of the 1990 Federal Clean Air Act
Amendments will not have a material adverse effect on our financial condition
or results of operations.
Solid Waste
We generate non-hazardous solid wastes that are subject to the requirements
of the Federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA is considering the adoption of stricter disposal
standards for non-hazardous wastes, including oil and gas wastes. RCRA also
governs the disposal of hazardous wastes. We are not currently required to
comply with a substantial portion of the RCRA requirements because our
operations generate minimal quantities of hazardous wastes. However, it is
possible that additional wastes, which could include wastes currently generated
during operations, will in the future be designated as "hazardous wastes."
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Such changes in the regulations could result in
additional capital expenditures or operating expenses.
Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as "Superfund," imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of our ordinary operations, we may generate waste that falls within
CERCLA's definition of a "hazardous substance." We may be jointly and severally
liable under CERCLA for all or part of the costs required to clean up sites at
which such hazardous substances have been disposed of or released into the
environment.
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We currently own or lease, and have in the past owned or leased, properties
where hydrocarbons are being or have been handled. Although we have utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or released on or
under the properties owned or leased by us or on or under other locations where
these wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under our control. These
properties and wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators), to clean up contaminated property (including
contaminated groundwater) or to perform remedial plugging operations to prevent
future contamination.
OSHA
We are also subject to the requirements of the Federal Occupational Safety
and Health Act ("OSHA") and comparable state statutes that regulate the
protection of the health and safety of workers. In addition, the OSHA hazard
communication standard requires that certain information be maintained about
hazardous materials used or produced in operations and that this information be
provided to employees, state and local government authorities and citizens. We
believe that our operations are in substantial compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to regulated substances.
Endangered Species Act
The Endangered Species Act ("ESA") restricts activities that may affect
endangered species or their habitats. While certain of our facilities are in
areas that may be designated as habitat for endangered species, we believe that
we are in substantial compliance with the ESA. However, the discovery of
previously unidentified endangered species could cause us to incur additional
costs or operation restrictions or bans in the affected area.
Hazardous Materials Transportation Requirements
The DOT regulations affecting pipeline safety require pipeline operators to
implement measures designed to reduce the environmental impact of oil discharge
from onshore oil pipelines. These regulations require operators to maintain
comprehensive spill response plans, including extensive spill response training
for pipeline personnel. In addition, DOT regulations contain detailed
specifications for pipeline operation and maintenance. We believe our
operations are in substantial compliance with such regulations.
Environmental Remediation
In connection with our acquisition of Scurlock Permian, we identified a
number of areas of potential environmental exposure. Under the terms of our
acquisition agreement, Marathon Ashland is fully indemnifying us for areas of
environmental exposure which were identified at the time of the acquisition,
including any and all liabilities associated with two superfund sites at which
it is alleged Scurlock Permian deposited waste oils as well as any potential
liability for hydrocarbon soil and water contamination at a number of Scurlock
Permian facilities. For environmental liabilities which were not identified at
the time of the acquisition but which occurred prior to the closing, we have
agreed to pay the costs relating to matters that are under $25,000. Our
liabilities relating to matters discovered prior to May 2003 and that exceed
$25,000, is limited to an aggregate of $1 million, with Marathon Ashland
indemnifying us for any excess amounts. Marathon Ashland's indemnification
obligations for identified sites extend indefinitely while its obligations for
non-identified sites extend to matters discovered within four years. While we
do not believe that our liability, if any, for environmental contamination
associated with our Scurlock Permian assets will be material, there can be no
assurance in that regard. Moreover, should we be found liable, we believe that
our indemnification from
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<PAGE>
Marathon Ashland should prevent such liability from having a material adverse
effect on our financial condition or results of operations.
In connection with our acquisition of the West Texas Gathering System, we
agreed to be responsible for pre-acquisition environmental liabilities up to an
aggregate amount of $1 million, while Chevron Pipe Line Company agreed to
remain solely responsible for liabilities which are discovered prior to July
2002 which exceed this $1 million threshold. To date, we have identified a
number of sites along our West Texas Gathering System on which there may be
hydrocarbon contaminated soils. While we do not know the cost of remediation of
these sites, we believe our indemnification arrangement with Chevron Pipe Line
Company should prevent such costs, if any, from having a material adverse
effect on our financial condition or results of operations.
From 1994 to 1997, the Venice, Louisiana terminal experienced several
releases of crude oil and jet fuel into the soil. The Louisiana Department of
Environmental Quality has been notified of the releases. Marathon Ashland has
performed some soil remediation related to the releases. The extent of the
contamination at the sites is uncertain and there is a potential for
groundwater contamination. We do not expect expenditures related to this
terminal to be material, although we can provide no assurances in that regard.
During 1997, the All American Pipeline experienced a leak in a segment of
its pipeline in California which resulted in an estimated 12,000 barrels of
crude oil being released into the soil. Immediate action was taken to repair
the pipeline leak, contain the spill and to recover the released crude oil. We
have expended approximately $400,000 to date in connection with this spill and
do not expect any additional expenditures to be material, although we can
provide no assurances in that regard.
Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and
groundwater underlying the site due to activities on the property. We are
undertaking a voluntary state-administered remediation of the contamination on
the property to determine the extent of the contamination. We have proposed
extending the scope of our study and are awaiting the state's response. We have
spent approximately $100,000 to date in investigating the contamination at this
site. We do not anticipate the total additional costs related to this site to
exceed $250,000, although no assurance can be given that the actual cost could
not exceed such estimate. In addition, a portion of any such costs may be
reimbursed to us from Plains Resources. See "Certain Relationships and Related
Transactions--Relationship with Plains Resources--Indemnity from the General
Partner."
We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover releases that were previously
unidentified. While we maintain an extensive inspection program designed to
prevent and, as applicable, to detect and address such releases promptly,
damages and liabilities incurred due to any future environmental releases from
our assets may substantially affect our business.
Title to Properties
Substantially all of our pipelines are constructed on rights-of-way granted
by the apparent record owners of such property and in some instances such
rights-of-way are revocable at the election of the grantor. In many instances,
lands over which rights-of-way have been obtained are subject to prior liens
which have not been subordinated to the right-of-way grants. In some cases, not
all of the apparent record owners have joined in the right-of-way grants, but
in substantially all such cases, signatures of the owners of majority interests
have been obtained. We have obtained permits from public authorities to cross
over or under, or to lay facilities in or along water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor. We have also obtained permits from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantor's election. In some cases, property for
pipeline purposes was purchased in fee. All of the pump stations are located on
property owned in fee or property under long-term leases. In certain states and
under certain circumstances, we have the right of eminent domain to acquire
rights-of-way and lands necessary for our common carrier pipelines.
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<PAGE>
Some of the leases, easements, rights-of-way, permits and licenses
transferred to us, upon our formation in 1998 and in connection with
acquisitions we have made since that time, required the consent of the grantor
to transfer such rights, which in certain instances is a governmental entity.
The general partner believes that it has obtained such third-party consents,
permits and authorizations as are sufficient for the transfer to us of the
assets necessary for us to operate our business in all material respects as
described in this report. With respect to any consents, permits or
authorizations which have not yet been 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 our
business.
The general partner believes that we have satisfactory title to all of our
assets. Although title to such properties are subject to encumbrances in
certain cases, such as customary interests generally retained in connection
with acquisition of real property, liens related to environmental liabilities
associated with historical operations, liens for current taxes and other
burdens and minor easements, restrictions and other encumbrances to which the
underlying properties were subject at the time of acquisition by our
predecessor or us, the general partner believes that none of such burdens will
materially detract from the value of such properties or from our interest
therein or will materially interfere with their use in the operation of our
business.
Employees
To carry out our operations, the general partner or its affiliates employs
approximately 910 employees. None of the employees of the general partner is
represented by labor unions, and the general partner considers its employee
relations to be good.
Legal Proceedings
We are a party to various legal actions that have arisen in the ordinary
course of our business. We do not believe that the resolution of these matters
will have a material adverse effect on our financial condition or results of
operations.
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MANAGEMENT
The General Partner Manages Plains All American Pipeline
The general partner manages our operations and activities. Unitholders do
not directly or indirectly participate in our management or operation. The
general partner owes a fiduciary duty to the unitholders. The general partner
is liable, as a general partner, for all of our debts (to the extent not paid
from our assets), except for indebtedness or other obligations that are made
specifically non-recourse to it. However, whenever possible, the general
partner intends to incur indebtedness or other obligations that are non-
recourse.
Two members of the board of directors of the general partner serve on a
conflicts committee to review specific matters which the board believes may
involve conflicts of interest. The conflicts committee will determine if the
resolution of the conflict of interest is fair and reasonable to Plains All
American Pipeline. The members of the conflicts committee may not be officers
or employees of the general partner or directors, officers or employees of its
affiliates. Any matters approved by the conflicts committee will be
conclusively deemed to be fair and reasonable to us, approved by all of our
partners, and not a breach by the general partner of any duties it may owe
Plains All American Pipeline or our unitholders. In addition, the members of
the conflicts committee also serve on an audit committee which reviews our
external financial reporting, recommends engagement of our independent auditors
and review procedures for internal auditing and the adequacy of our internal
accounting controls.
As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by the officers and are subject to the oversight of the
directors of our general partner. Most of our operational personnel are
employees of the general partner.
Some officers of our general partner may spend a substantial amount of time
managing the business and affairs of Plains Resources and its affiliates. These
officers may face a conflict regarding the allocation of their time between our
business and the other business interests of Plains Resources. Our general
partner intends to cause its officers to devote as much time to the management
of our business and affairs as is necessary for the proper conduct of our
business and affairs.
Directors and Executive Officers of 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 for one-year terms.
<TABLE>
<CAPTION>
Name Age Position with General Partner
---- --- -----------------------------
<S> <C> <C>
Greg L. Armstrong....... 41 Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis........ 42 President, Chief Operating Officer and Director
Phillip D. Kramer....... 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
Michael J. Latiolais.... 44 Vice President--Administration
Mark F. Shires.......... 42 Vice President--Operations
Cynthia A. Feeback...... 42 Treasurer
Everardo Goyanes........ 55 Director & Member of Audit and Conflicts Committees
Robert V. Sinnott....... 50 Director & Member of Audit and Compensation Committees
Arthur L. Smith......... 46 Director & Member of Audit, Conflicts & Compensation
Committees
</TABLE>
Greg L. Armstrong has served as Chairman of the Board, Chief Executive
Officer and Director of the general partner since its formation. In addition,
he has been President, Chief Executive Officer and Director of Plains Resources
since 1992. He previously served Plains Resources as: President and Chief
Operating Officer from October to December 1992; Executive Vice President and
Chief Financial Officer from June to October
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1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice
President and Chief Financial Officer from 1984 to 1991; Corporate Secretary
from 1981 to 1988; and Treasurer from 1984 to 1987.
Harry N. Pefanis has served as President, Chief Operating Officer and
Director of the general partner since its formation. In addition, he has been
Executive Vice President--Midstream of Plains Resources since May 1998. He
previously served Plains Resources as: Senior Vice President from February 1996
until May 1998; Vice President--Products Marketing from 1988 to February 1996;
Manager of Products Marketing from 1987 to 1988; and Special Assistant for
Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of the
Plains Midstream Subsidiaries until the formation of Plains All American
Pipeline.
Phillip D. Kramer has served as Executive Vice President and Chief Financial
Officer of the general partner since its formation. In addition, he has been
Executive Vice President, Chief Financial Officer and Treasurer of Plains
Resources since May 1998. He previously served Plains Resources as: Senior Vice
President, Chief Financial Officer and Treasurer from May 1997 until May 1998;
Vice President, Chief Financial Officer and Treasurer from 1992 to 1997; Vice
President and Treasurer from 1988 to 1992; Treasurer from 1987 to 1988; and
Controller from 1983 to 1987.
George R. Coiner has served as Senior Vice President of the general partner
since its formation. In addition, he was Vice President of Plains Marketing &
Transportation Inc., a Plains Midstream Subsidiary, from November 1995 until
the formation of Plains All American Pipeline. Prior to joining Plains
Marketing & Transportation Inc., he was Vice President, Marketing with Scurlock
Permian Corp.
Michael R. Patterson has served as Senior Vice President, General Counsel
and Secretary of the general partner since its formation. In addition, he has
been Vice President, General Counsel and Secretary of Plains Resources since
1988. He previously served Plains Resources as Vice President and General
Counsel from 1985 to 1988.
Michael J. Latiolais has served as Vice President--Administration of the
general partner since August 1999 and as Controller of the general partner from
July 1998 through August 1999. In addition, he was Vice President and
Controller for All American Pipeline Company, Celeron Gathering Corporation and
Celeron Trading & Transportation Company from 1994 until such companies were
merged into the operating partnerships of Plains All American Pipeline. He
served as Controller of such companies from 1985 to 1994.
Mark F. Shires has served as Vice President--Operations of the general
partner since August 1999. He served as Manager of Operations for the general
partner from April 1999 until August 1999 when he was elected to his current
position. In addition, he was a business consultant from 1996 until April 1999.
He served as a consultant to Plains Marketing & Transportation Inc. and Plains
All American Pipeline from May 1998 until April 1999. He previously served as
President of Plains Terminal & Transfer Corporation, a Plains Midstream
Subsidiary, from 1993 to 1996.
Cynthia A. Feeback has served as Treasurer of the general partner since its
formation. In addition, she has been Vice President--Accounting and Assistant
Treasurer of Plains Resources since May 1999. She previously served Plains
Resources as Assistant Treasurer and Controller from May 1998 to May 1999;
Controller and Principal Accounting Officer from 1993 to 1998; Controller from
1990 to 1993; and Accounting Manager from 1988 to 1990.
Everardo Goyanes has served as Director and Member of Audit and Conflicts
Committees since May 1999. In addition, he is a financial consultant
specializing in natural resources. From 1989 to 1998, he was Managing Director
of the Natural Resources Group of ING Baring Furman Selz (a commercial banking
firm). He was a financial consultant from 1987 to 1989 and was Vice President--
Finance of Forest Oil Corporation from 1983 to 1987.
Robert V. Sinnott has served as Director and Member of Audit and
Compensation Committees since September 1998. In addition, he has been Senior
Vice President of Kayne Anderson Investment Management,
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Inc. (an investment management firm) since 1992. He was Vice President and
Senior Securities Officer of the Investment Banking Division of Citibank from
1986 to 1992. He is also a director of Plains Resources and Glacier Water
Services, Inc. (a vended water company).
Arthur L. Smith has served as Director and Member of Audit, Conflicts and
Compensation Committees since February 1999. In addition, he 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 1988 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.
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 Plains All American Pipeline.
The general partner and its affiliates, including Plains Resources, performing
services for Plains All American Pipeline are reimbursed for all expenses
incurred on our behalf, including the costs of employee, officer and director
compensation and benefits properly allocable to us, and all other expenses
necessary or appropriate to the conduct of the business of, and allocable to,
us. The partnership agreement provides that the general partner will determine
the expenses that are allocable to Plains All American Pipeline in any
reasonable manner determined by the general partner in its sole discretion.
Executive Compensation
We formed the partnership 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 Plains All American Pipeline
in 1998. No officer of the general partner received compensation for services
to Plains All American Pipeline in 1998 in amounts greater than $100,000.
Employment Agreement
Mr. Pefanis has an employment agreement with Plains Resources. Under 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 of
three years, commencing November 23, 1998, 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 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 defined in the employment agreement, the term of the employment
agreement will be automatically extended for three years. If Mr. Pefanis'
employment is terminated during the one-year period following either event by
him for a good reason, as defined in the employment agreement, or by Plains
Resources other than for death, disability or cause, he will be entitled to a
lump sum severance amount equal to three times the sum of his highest rate of
annual base salary and the largest annual bonus paid during the three preceding
years.
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Long-Term Incentive Plan
The general partner has adopted the Plains All American Inc. 1998 Long-Term
Incentive Plan for employees and directors of the general partner and its
affiliates who perform services for us. The Long-Term Incentive Plan consists
of two components, a restricted unit plan and a unit option plan. The Long-Term
Incentive Plan currently permits the grant of restricted units and unit options
covering an aggregate of 975,000 common units. The plan is administered by the
compensation committee of 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 September 8, 1999, we have granted an aggregate of approximately 500,000
restricted units to employees of the general partner, including 60,000, 30,000
and 12,500 units granted to Messrs. Pefanis, Coiner and Latiolais,
respectively. The compensation committee may, in the future, determine to make
additional grants under the plan to employees and directors containing such
terms as the compensation committee shall determine. In general, restricted
units granted to employees during the subordination period will vest only upon,
and in the same proportions as, the conversion of the subordinated units to
common units. Grants made to non-employee directors of 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 us or any
other person, or any combination of the foregoing. The general partner will be
entitled to reimbursement by us for the cost incurred in acquiring common
units. If we issue new common units upon vesting of the restricted units, the
total number of common units outstanding will increase. Following the
subordination period, the compensation committee, in its discretion, may grant
tandem distribution equivalent rights with respect to restricted units.
The issuance of the common units pursuant to the restricted unit plan is
intended to serve as a means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity appreciation of the
common units. Therefore, no consideration will be payable by the plan
participants upon receipt of the common units, and we will receive no
remuneration for the units.
Unit Option Plan. The Unit Option Plan currently permits the grant of
options covering common units. No grants have been made under the Unit Option
Plan. The compensation committee may, in the future, determine to make grants
under the 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 us 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 us 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 us. If we issue
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 us the
proceeds it received from the optionee upon exercise of the unit option.
The unit option plan has been designed to furnish additional compensation to
employees and directors and to align their economic interests with those of
common unitholders. The general partner's board of directors in
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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 of the plan from time to time,
including increasing the number of common units with respect to which awards
may be granted; provided, however, that no change in any outstanding grant may
be made that would materially impair the rights of the participant without the
consent of such participant.
Transaction Grant Agreements
In addition to the grants made under the Restricted Unit Plan described
above, the general partner, at no cost to us, agreed to transfer approximately
400,000 of its affiliates' common units to certain key employees of the general
partner. Generally, approximately 81,000 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
53,000 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 prior to January 1, 2002.
The compensation expense incurred in connection with these grants will be
funded by the general partner, without reimbursement by us. Of the 400,000
common units, 75,000 were allocated to each of Messrs. Armstrong and 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 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 us 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 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.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units held by
beneficial owners of 5% or more of the units, by directors and officers of the
general partner and by all directors and executive officers of the general
partner as a group as of September 1, 1999.
<TABLE>
<CAPTION>
Percentage Class B Percentage of Percentage of Percentage
Common of Common Common Class B Subordinated Subordinated of Total
Name of Beneficial Owner Units Units Units Common Units Units Units Units
- ------------------------ --------- ---------- --------- ------------- ------------ ------------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Plains Resources Inc.
(1).................... 6,974,239(3) 34.8% 1,307,190 100% 10,029,619 100% 58.3%
Plains All American
Inc.(2)................ 6,974,239(3) 34.8% 1,307,190 100% 10,029,619 100% 58.3%
Greg L. Armstrong....... 93,000(3) (5) 0 0 0 0 (5)
Harry N. Pefanis........ 147,000(3)(4) (5) 0 0 0 0 (5)
Phillip D. Kramer....... 6,000 (5) 0 0 0 0 (5)
George R. Coiner........ 85,000(3)(4) (5) 0 0 0 0 (5)
Michael R. Patterson.... 7,000 (5) 0 0 0 0 (5)
Michael J. Latiolais.... 12,500(4) (5) 0 0 0 0 (5)
Mark F. Shires.......... 0 (5) 0 0 0 0 (5)
Cynthia A. Feeback...... 500 (5) 0 0 0 0 (5)
Everardo Goyanes........ 0 (5) 0 0 0 0 0
Robert V. Sinnott....... 5,000 (5) 0 0 0 0 (5)
Arthur L. Smith......... 7,500 (5) 0 0 0 0 (5)
All directors and
executive officers as a
group
(11 persons)........... 363,500 1.8%(6) 0 0 0 0 1.2%(6)
</TABLE>
- --------
(1) Plains Resources Inc. is the sole stockholder of Plains All American Inc.,
the general partner. The address of Plains Resources Inc. is 500 Dallas,
Suite 700, Houston, Texas 77002.
(2) The address of Plains All American Inc. is 500 Dallas, Suite 700, Houston,
Texas 77002. The record holder of such common units and subordinated units
is PAAI LLC, a wholly-owned subsidiary of Plains All American Inc., whose
address is 500 Dallas, Suite 700, Houston, Texas 77002.
(3) Includes 400,000 common units owned by affiliates of the general partner to
be transferred to employees pursuant to transaction grant agreements,
subject to vesting conditions. The recipents of these grants include: Mr.
Armstrong--75,000; Mr. Pefanis--75,000; and Mr. Coiner--50,000. See
"Management--Transaction Grant Agreements".
(4) Includes the following unvested common units issuable under the Long-Term
Incentive Plan to: Mr. Pefanis--60,000; Mr. Coiner--30,000; and Mr.
Latiolais--12,500. See "Management--Long-Term Incentive Plan" for vesting
conditions of these grants.
(5) Less than one percent.
(6) Assumes the vesting of the units granted pursuant to the transaction grant
agreements and under the Long-Term Incentive Plan as described in footnotes
(3) and (4) above to the named officers and directors. See "Management--
Long-Term Incentive Plan" for vesting conditions of these grants.
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The following table sets forth the beneficial ownership of Plains Resources
common stock, par value $.10 per share, held by directors and executive
officers of the general partner as of September 1, 1999.
<TABLE>
<CAPTION>
Shares
Beneficially Percent
Name of Beneficial Owner Owned(1) of Class
------------------------ ------------ --------
<S> <C> <C>
Greg L. Armstrong.................................. 272,693 1.6%
Harry N. Pefanis................................... 137,465 (2)
Phillip D. Kramer.................................. 159,886 (2)
George R. Coiner................................... 19,982 (2)
Michael R. Patterson............................... 134,316 (2)
Michael J. Latiolais............................... 209 (2)
Mark F. Shires..................................... 0 0
Cynthia A. Feeback................................. 49,790 (2)
Everardo Goyanes................................... 0 0
Robert V. Sinnott(3)............................... 79,513 (2)
Arthur L. Smith.................................... 2,000 (2)
Directors and Executive Officers as a group (11
persons).......................................... 855,854 4.8%
</TABLE>
- --------
(1) Includes both outstanding shares of Plains Resources Common Stock and
shares of Plains Resources Common Stock such person has the right to
acquire within 60 days after the date of this prospectus by exercise of
outstanding stock options. Shares subject to exercisable stock options
include 266,750 shares for Mr. Armstrong; 132,750 for Mr. Pefanis; 153,500
for Mr. Kramer; 13,750 shares for Mr. Coiner; 117,088 for Mr. Patterson;
48,500 for Ms. Feeback; and 45,000 for Mr. Sinnott.
(2) Less than one percent
(3) Includes 29,580 shares of Plains Resources Common Stock issuable upon the
conversion of 1,065 shares of Plains Resources Series E Cumulative
Convertible Preferred Stock.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Rights of the General Partner
After this offering, the general partner and its affiliates will own
8,281,429 common units, including 1,307,190 Class B common units, and
10,029,619 subordinated units, representing an aggregate 52.8% limited partner
interest in Plains All American Pipeline (52.3% if the Underwriters' over-
allotment option is exercised in full). In addition, the general partner will
own an aggregate 2% general partner interest in Plains All American Pipeline
and the operating partnerships on a combined basis. Through the general
partner's ability, as general partner, to manage and operate Plains All
American Pipeline and the ownership of 8,281,429 common units, including
1,307,190 Class B 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 Plains All American Pipeline),
the general partner will have the ability to control the management of Plains
All American Pipeline.
Relationship with Plains Resources
General
We have extensive ongoing relationships with Plains Resources. These
relationships include:
. Plains Resources' wholly owned subsidiary, Plains All American Inc.,
serving as our general partner;
. the Omnibus Agreement, providing for the resolution of certain conflicts
arising from the conduct of Plains All American Pipeline and Plains
Resources of related businesses (see "Conflicts of Interest and Fiduciary
Responsibilities--Conflicts of Interest--The General Partner's Affiliates
May Compete with the Partnership Under Certain Circumstances") and for
the general partners indemnification of us for certain matters; and
. the Marketing Agreement with Plains Resources, providing for the
marketing of Plains Resources' crude oil production. See "Business--
Terminalling and Storage Activities and Gathering and Marketing
Activities."
Transactions with Affiliates
On May 12, 1999, Plains Scurlock Permian, L.P., a limited partnership of
which Plains All American Inc. is the general partner and Plains Marketing,
L.P. is the limited partner, completed the acquisition of Scurlock Permian LLC
from Marathon Ashland Petroleum LLC. See "Business--Business Strategy." To
finance a portion of the purchase price, we sold to our general partner 1.3
million Class B common units at $19.125 per unit, the market value of our
common units on May 12, 1999.
The Class B units are initially pari passu with common units with respect to
distributions, and after six months are convertible into common units upon the
request of the Class B unitholders and the approval of a majority of the common
units voting at a meeting of unitholders. If the approval of such conversion by
the common unitholders is not obtained within 120 days of such request, the
Class B unitholders will be entitled to receive distributions, on a per unit
basis, equal to 110% of the amount of distributions paid on a common unit, with
such distribution right increasing to 115% if such approval is not secured
within 90 days after the end of the 120-day period. Except for the vote to
approve the conversion, Class B units have the same voting rights as the common
units.
Prior to the Marketing Agreement, our predecessor marketed crude oil
production of Plains Resources, its subsidiaries and its royalty owners. Our
predecessor paid approximately $83.4 million, $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 prices.
Our predecessor did not recognize a profit on the sale of the crude oil
purchased from Plains Resources. For the first six months of 1999, Plains
Resources produced approximately
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18,600 barrels per day which were subject to the Marketing Agreement. We paid
approximately $40.6 million for such production and generated approximately
$674,000 in revenue under the terms of that agreement.
The general partner has sole responsibility for conducting our business and
managing our operations and owns all of the incentive distribution rights. Some
of the senior executives who currently manage our business also manage and
operate the business of Plains Resources. The general partner does not receive
any management fee or other compensation in connection with its management of
our business, but it is reimbursed for all direct and indirect expenses
incurred on our behalf. For the six months ended June 30, 1999, the general
partner and its affiliates incurred $13.3 million of direct and indirect
expenses on our behalf.
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 in July 1998, Wingfoot agreed to indemnify the general partner
for certain environmental and other liabilities. The indemnity is subject to
limits of:
. $10 million with respect to matters of corporate authorization and title
to shares;
. $21.5 million with respect to condition of rights-of-way, lease rights
and undisclosed liabilities and litigation; and
. $30 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. We have also agreed to be solely
responsible for the cumulative aggregate amount of losses resulting from the
oil leak from the All American Pipeline to the extent such losses do not exceed
$350,000. Any costs in excess of $350,000 will be applied to the $1 million
deductible for the Wingfoot environmental indemnity. The general partner has
agreed to indemnify us for environmental and other liabilities to the extent it
is indemnified by Wingfoot.
Plains Resources has agreed to indemnify us for environmental liabilities
related to the assets of the Plains Midstream Subsidiaries transferred to us
that arose prior to closing and are discovered within three years after closing
(excluding liabilities resulting from a change in law after closing). Plains
Resources' indemnification obligation is capped at $3 million.
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CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the
relationships between the general partner and its affiliates (including Plains
Resources), on the one hand, and Plains All American Pipeline and its limited
partners, on the other hand. The directors and officers of the general partner
have fiduciary duties to manage the general partner in a manner beneficial to
its owners. At the same time, the general partner has a fiduciary duty to
manage Plains All American Pipeline in a manner beneficial to Plains All
American Pipeline and the unitholders.
The partnership agreement contains provisions that allow the general partner
to take into account the interests of parties in addition to Plains All
American Pipeline in resolving conflicts of interest. In effect, these
provisions limit the general partner's fiduciary duties to the unitholders. The
partnership agreement also restricts the remedies available to unitholders for
actions taken that might, without those limitations, constitute breaches of
fiduciary duty. Whenever a conflict arises between the general partner or its
affiliates, on the one hand, and Plains All American Pipeline or any other
partner, on the other, the general partner will resolve that conflict. A
conflicts committee of the board of directors of the general partner will, at
the request of the general partner, review conflicts of interest. The general
partner will not be in breach of its obligations under the partnership
agreement or its duties to Plains All American Pipeline or the unitholders if
the resolution of the conflict is considered to be fair and reasonable to
Plains All American Pipeline. Any resolution is considered to be fair and
reasonable to Plains All American Pipeline if that resolution is:
. approved by the conflicts committee, although no party is obligated to
seek approval and the general partner may adopt a resolution or course of
action that has not received approval;
. on terms no less favorable to Plains All American Pipeline than those
generally being provided to or available from unrelated third parties; or
. fair to Plains All American Pipeline, taking into account the totality of
the relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous to Plains
All American Pipeline.
In resolving a conflict, the general partner may, unless the resolution is
specifically provided for in the partnership agreement, consider:
. the relative interests of the parties involved in the conflict or
affected by the action;
. any customary or accepted industry practices or historical dealings with
a particular person or entity; and
. generally accepted accounting practices or principles and other factors
it considers relevant, if applicable.
Conflicts of interest could arise in the situations described below, among
others:
Actions taken by the general partner may affect the amount of cash available
for distribution to unitholders or accelerate the right to convert subordinated
units.
The amount of cash that is available for distribution to unitholders is
affected by decisions of the general partner regarding matters, including:
. amount and timing of asset purchases and sales;
. cash expenditures;
. borrowings;
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. issuance of additional units; and
. the creation, reduction or increase of reserves in any quarter.
In addition, borrowings by Plains All American Pipeline do not constitute a
breach of any duty owed by the general partner to the unitholders, including
borrowings that have the purpose or effect of:
. enabling the general partner to receive distributions on any subordinated
units held by them or the incentive distribution rights; or
. hastening the expiration of the subordination period.
The partnership agreement provides that Plains All American Pipeline, the
operating partnerships and the subsidiaries may borrow funds from the general
partner and its affiliates. The general partner and its affiliates may not
borrow funds from Plains All American Pipeline, the operating partnerships or
the subsidiaries.
We do not have any officers or employees and rely solely on officers and
employees of the general partner and its affiliates. Affiliates of the general
partner conduct businesses and activities of their own in which we have no
economic interest. If these separate activities are significantly greater than
our activities, there could be material competition for the time and effort of
the officers and employees who provide services to the general partner. Some of
the officers of the general partner are not required to work full time on our
affairs. These officers are required to devote significant time to the affairs
of Plains Resources or its affiliates and are compensated by these affiliates
for the services rendered to them.
We will reimburse the general partner and its affiliates for expenses.
We will reimburse the general partner and its affiliates for costs incurred
in managing and operating Plains All American Pipeline, including costs
incurred in rendering corporate staff and support services to Plains All
American Pipeline. The partnership agreement provides that the general partner
will determine the expenses that are allocable to Plains All American Pipeline
in any reasonable manner determined by the general partner in its sole
discretion.
The general partner intends to limit the liability of the general partner
regarding our obligations.
The general partner intends to limit the liability of the general partner
under contractual arrangements so that the other party has recourse only to our
assets, and not against the general partner or its assets. The partnership
agreement provides that any action taken by the general partner to limit its
liability, or that of us, is not a breach of the general partner's fiduciary
duties, even if we could have obtained more favorable terms without the
limitation on liability.
Common unitholders will have no right to enforce obligations of the general
partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and the general partner and its
affiliates, on the other, will not grant to the unitholders, separate and apart
from us, the right to enforce the obligations of the general partner and its
affiliates in our favor.
Contracts between us, on the one hand, and the general partner and its
affiliates, on the other, will not be the result of arm's-length negotiations.
The partnership agreement allows the general partner to pay itself or its
affiliates for any services rendered, provided these services are rendered on
terms that are fair and reasonable to us. The general partner may also enter
into additional contractual arrangements with any of its affiliates on our
behalf. Neither the partnership agreement nor any of the other agreements,
contracts and arrangements between us, on the one
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hand, and the general partner and its affiliates, on the other, are or will be
the result of arm's-length negotiations.
The general partner and its affiliates will have no obligation to permit us
to use any facilities or assets of the general partner and its affiliates,
except as may be provided in contracts entered into specifically dealing with
that use. There is no obligation of the general partner and its affiliates to
enter into any contracts of this kind.
Common units are subject to the general partner's limited call right.
The general partner may exercise its right to call and purchase common units
as provided in the partnership agreement or assign this right to one of its
affiliates or to us. The general partner may use its own discretion, free of
fiduciary duty restrictions, in determining whether to exercise this right. As
a consequence, a common unitholder may have his common units purchased from him
at an undesirable time or price. For a description of this right, see "The
Partnership Agreement--Limited Call Right."
We may not choose to retain separate counsel for ourselves or for the
holders of common units.
The attorneys, independent accountants and others who perform services for
us have been retained by the general partner. Attorneys, independent
accountants and others who perform services for us are selected by the general
partner or the conflicts committee and may also perform services for the
general partner and its affiliates. We may retain separate counsel for
ourselves or the holders of common units in the event of a conflict of interest
arising between the general partner and its affiliates, on the one hand, and us
or the holders of common units, on the other, depending on the nature of the
conflict. We do not intend to do so in most cases.
The general partner's affiliates may compete with us.
The partnership agreement provides that the general partner will be
restricted from engaging in any business activities other than those incidental
to its ownership of interests in us. Except as provided in the partnership
agreement and the omnibus agreement among us, the operating partnerships, the
general partner and Plains Resources, affiliates of the general partner are not
prohibited from engaging in other businesses or activities, including those
that might be in direct competition with us. The omnibus agreement provides
that, so long as the general partner is an affiliate of Plains Resources,
neither Plains Resources nor any of its affiliates (other than the general
partner, Plains All American Pipeline and our controlled affiliates) (a "Plains
entity") will engage in or acquire any business engaged in the following
activities (a "restricted business"):
. crude oil storage, terminalling and gathering activities in the lower 48
states for any party other than a Plains entity or Plains All American
Pipeline or our affiliates;
. crude oil marketing activities; and
. transportation of crude oil by pipeline in the lower 48 states for any
party other than a Plains entity or Plains All American Pipeline or our
affiliates.
Notwithstanding the foregoing, a Plains entity may engage in a restricted
business if:
. The restricted business was engaged in by the Plains entity as of the
date of our formation.
. The restricted business is conducted pursuant to and in accordance with
the terms of the Marketing Agreement or any other arrangement entered
into with us with the concurrence of the conflicts committee.
. The value of the assets acquired in a transaction that comprise a
restricted business does not exceed $10 million.
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. The value of the assets acquired in a transaction that comprise a
restricted business exceeds $10 million and the general partner (with the
concurrence of the conflicts committee) has elected not to cause us to
pursue such opportunity.
Except as provided in the omnibus agreement, a Plains entity is free to
engage in any type of business activity whatsoever, including those that may be
in direct competition with us. The omnibus agreement may not be amended without
the concurrence of the conflicts committee.
The omnibus agreement may be terminated by Plains Resources upon a "change
of control" of Plains Resources. A "change of control" will be deemed to occur
upon:
. the sale of substantially all of the assets of Plains Resources;
. the acquisition of more than 50% of the outstanding common equity of
Plains Resources by any entity; or
. the consummation of a merger following which the holders of Plains
Resources' voting securities hold less than 50% of the voting securities
of the surviving entity.
Accordingly, in the event of a "change of control" of Plains Resources, the
owner of the general partner will not be restricted from engaging in businesses
which compete directly with us. A sale or transfer of the general partner
interest or capital stock of the general partner will result in the purchaser
or transferee being bound by the noncompetition provisions of the omnibus
agreement.
Fiduciary Duties Owed to Unitholders by the General Partner are Prescribed by
Law and the Partnership Agreement
The general partner is accountable to us and our unitholders as fiduciaries.
The Delaware Act provides that Delaware limited partnerships may, in their
partnership agreements, restrict or expand the fiduciary duties owed by the
general partner to limited partners and the partnership.
The partnership agreement contains various provisions restricting the
fiduciary duties that might otherwise be owed by the general partner. The
following is a summary of the material restrictions of the fiduciary duties
owed by the general partner to the limited partners:
State-law fiduciary duty
standards................. Fiduciary duties are generally considered to
include an obligation to act with due care and
loyalty. The duty of care, in the absence of a
provision in a partnership agreement providing
otherwise, would generally require a general
partner to act for the partnership in the same
manner as a prudent person would act on their own
behalf. The duty of loyalty, in the absence of a
provision in a partnership agreement providing
otherwise, would generally prohibit a general
partner of a Delaware limited partnership from
taking any action or engaging in any transaction
where a conflict of interest is present.
The Delaware Act generally provides that a limited
partner may institute legal action on our behalf
to recover damages from a third party where a
general partner has refused to institute the
action or where an effort to cause a general
partner to do so is not likely to succeed. In
addition, the statutory or case law of some
jurisdictions may permit a limited partner to
institute legal action on behalf of himself and
all other similarly situated limited partners to
recover damages from a general partner for
violations of its fiduciary duties to the limited
partners.
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Partnership agreement
modified standards........ The partnership agreement contains provisions that
waive or consent to conduct by the general partner
and its affiliates that might otherwise raise
issues as to compliance with fiduciary duties or
applicable law. For example, the partnership
agreement permits the general partner to make a
number of decisions in its "sole discretion." This
entitles the general partner to consider only the
interests and factors that it desires and it shall
have no duty or obligation to give any
consideration to any interest of, or factors
affecting, us, our affiliates or any limited
partner. Other provisions of the partnership
agreement provide that the general partner's
actions must be made in its reasonable discretion.
These standards reduce the obligations to which
the general partner would otherwise be held.
The partnership agreement generally provides that
affiliated transactions and resolutions of
conflicts of interest not involving a required
vote of unitholders must be "fair and reasonable"
to us under the factors previously set forth. In
determining whether a transaction or resolution is
"fair and reasonable" the general partner may
consider interests of all parties involved,
including its own. Unless the general partner has
acted in bad faith, the action taken by the
general partner shall not constitute a breach of
its fiduciary duty. These standards reduce the
obligations to which the general partner would
otherwise be held.
In addition to the other more specific provisions
limiting the obligations of the general partner,
the partnership agreement further provides that
the general partner and their officers and
directors will not be liable for monetary damages
to us, the limited partners or assignees for
errors of judgment or for any acts or omissions if
the general partner and those other persons acted
in good faith.
In order to become one of our limited partners, a common unitholder is
required to agree to be bound by the provisions in the partnership agreement,
including the provisions discussed above. This is in accordance with the policy
of the Delaware Act favoring the principle of freedom of contract and the
enforceability of partnership agreements. The failure of a limited partner or
assignee to sign a partnership agreement does not render the partnership
agreement unenforceable against that person.
We are required to indemnify the general partner and its officers,
directors, employees, affiliates, partners, members, agents and trustees, to
the fullest extent permitted by law, against liabilities, costs and expenses
incurred by the general partner or these other persons. This indemnification is
required if the general partner or these persons acted in good faith and in a
manner they reasonably believed to be in, or (in the case of a person other
than the general partner) not opposed to, our best interests. Indemnification
is required for criminal proceedings if the general partner or these other
persons had no reasonable cause to believe their conduct was unlawful. Thus,
the general partner could be indemnified for their negligent acts if they met
these requirements concerning good faith and our best interests. See "The
Partnership Agreement--Indemnification."
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DESCRIPTION OF THE COMMON UNITS
We are subject to the reporting and other requirements of the Exchange Act.
We are required to file periodic reports containing financial and other
information with the Securities and Exchange Commission.
The Units
The common units, including the Class B common units, and the subordinated
units represent limited partner interests in us. The holders of units are
entitled to participate in partnership distributions and exercise the rights or
privileges available to limited partners under our partnership agreement. For a
description of the relative rights and preferences of holders of common units
and subordinated units in and to partnership distributions, see "--Class B
Common Units," "Cash Distribution Policy" and "Description of Subordinated
Units." For a description of the rights and privileges of limited partners
under our partnership agreement, see "The Partnership Agreement."
Transfer Agent and Registrar
Duties
American Stock Transfer & Trust Company serves as registrar and transfer
agent for the common units. We pay all fees charged by the transfer agent for
transfers of common units, except the following will be paid by unitholders:
. surety bond premiums to replace lost or stolen certificates, taxes and
other governmental charges;
. special charges for services requested by a holder of a common unit; and
. other similar fees or charges.
There is no charge to unitholders for disbursements of our cash
distributions. We will indemnify the transfer agent, its agents and each of
their shareholders, directors, officers and employees against all claims and
losses that may arise out of acts performed or omitted for its activities in
that capacity, except for any liability due to any gross negligence or
intentional misconduct of the indemnified person or entity.
Resignation or Removal
The transfer agent may at any time resign, by notice to us, or be removed by
us. The resignation or removal of the transfer agent will become effective upon
our appointment of a successor transfer agent and registrar and its acceptance
of the appointment. If no successor has been appointed and accepted the
appointment within 30 days after notice of the resignation or removal, the
general partner is authorized to act as the transfer agent and registrar until
a successor is appointed.
Transfer of Common Units
The transfer of the common units to persons that purchase directly from the
underwriters will be accomplished through the completion, execution and
delivery of a transfer application by the investor. Any later transfers of a
common unit will not be recorded by the transfer agent or recognized by us
unless the transferee executes and delivers a transfer application. By
executing and delivering a transfer application, the transferee of common
units:
(1) becomes the record holder of the common units and is an assignee
until admitted into our partnership as a substituted limited partner;
(2) automatically requests admission as a substituted limited partner in
our partnership;
(3) agrees to be bound by the terms and conditions of, and executes, our
partnership agreement;
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(4) represents that the transferee has the capacity, power and authority
to enter into the partnership agreement;
(5) grants powers of attorney to officers of the general partner and any
liquidator of us as specified in the partnership agreement; and
(6) makes the consents and waivers contained in the partnership
agreement.
An assignee will become a substituted limited partner of our partnership
for the transferred common units upon the consent of the general partner and
the recording of the name of the assignee on our books and records. The
general partner may withhold its consent in its sole discretion.
Transfer applications may be completed, executed and delivered by a
transferee's broker, agent or nominee. We are entitled to treat the nominee
holder of a common unit as the absolute owner. In that case, the beneficial
holder's rights are limited solely to those that it has against the nominee
holder as a result of any agreement between the beneficial owner and the
nominee holder.
Common units are securities and are transferable according to the laws
governing transfer of securities. In addition to other rights acquired upon
transfer, the transferor gives the transferee the right to request admission
as a substituted limited partner in our partnership for the transferred common
units. A purchaser or transferee of common units who does not execute and
deliver a transfer application obtains only:
. the right to assign the common unit to a purchaser or other transferee;
and
. the right to transfer the right to seek admission as a substituted
limited partner in our partnership for the transferred common units.
Thus, a purchaser or transferee of common units who does not execute and
deliver a transfer application:
. will not receive cash distributions or federal income tax allocations,
unless the common units are held in a nominee or "street name" account
and the nominee or broker has executed and delivered a transfer
application; and
. may not receive some federal income tax information or reports furnished
to record holders of common units.
The transferor of common units will have a duty to provide the transferee
with all information that may be necessary to transfer the common units. The
transferor will not have a duty to insure the execution of the transfer
application by the transferee and will have no liability or responsibility if
the transferee neglects or chooses not to execute and forward the transfer
application to the transfer agent. See "The Partnership Agreement--Status as
Limited Partner or Assignee."
Until a common unit has been transferred on our books, we and the transfer
agent, notwithstanding any notice to the contrary, may treat the record holder
of the unit as the absolute owner for all purposes, except as otherwise
required by law or stock exchange regulations.
Class B Common Units
The Class B common units are initially pari passu with common units with
respect to distributions, and after six months are convertible into common
units upon the request of the Class B unitholder and the approval of a
majority of the common units voting at a meeting of unitholders. If the
approval of such conversion by the common unitholders is not obtained within
120 days of such request, the Class B unitholders will be entitled to receive
distributions, on a per unit basis, equal to 110% of the amount of
distributions paid on a common unit, with such distribution right increasing
to 115% if such approval is not secured within 90 days after the end of the
120-day period. Except for the vote to approve the conversion, Class B common
units have the same voting rights as the common units.
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DESCRIPTION OF THE SUBORDINATED UNITS
The subordinated units are a separate class of limited partner interests in
our partnership, and the rights of holders to participate in distributions to
partners differ from, and are subordinated to, the rights of the holders of
common units. For any given quarter, any available cash will first be
distributed to the general partner and to the holders of common units, until
the holders of common units have reviewed the minimum quarterly distribution
plus any arrearages, and then will be distributed to the holders of
subordinated units. See "Cash Distribution Policy."
Conversion of Subordinated Units
The subordination period will generally extend until the first day of any
quarter beginning after December 31, 2003, in which each of the following
events occur:
(1) distributions of available cash from operating surplus on the common
units and the subordinated units equal or exceed the sum of the minimum
quarterly distributions on all of the outstanding common units and
subordinated units for each of the three non-overlapping four-quarter
periods immediately preceding that date;
(2) the adjusted operating surplus generated during each of the three
immediately preceding non-overlapping four-quarter periods equals or
exceeds the sum of the minimum quarterly distributions on all of the
outstanding common units and subordinated units during those periods on a
fully diluted basis and the related distribution on the 2% general partner
interest during those periods; and
(3) there are no arrearages in payment of the minimum quarterly
distribution on the common units.
Before the end of the subordination period, one-quarter of the subordinated
units (up to 2,507,405 subordinated units) will convert into common units on a
one-for-one basis on the first day after the record date established for the
distribution for any quarter ending on or after December 31, 2001 and one-
quarter of the subordinated units (up to 2,507,405 subordinated units) will
convert into common units on a one-for-one basis on the first day after the
record date established for the distribution for any quarter ending on or after
December 31, 2002, if at the end of the applicable quarter each of the
following three events occurs:
(1) distributions of available cash from operating surplus on the common
units and the subordinated units equal or exceed the sum of the minimum
quarterly distributions on all of the outstanding common units and
subordinated units for each of the three non-overlapping four-quarter
periods immediately preceding that date;
(2) the adjusted operating surplus generated during each of the three
immediately preceding non-overlapping four-quarter periods equals or
exceeds the sum of the minimum quarterly distributions on all of the
outstanding common units and subordinated units during those periods on a
fully diluted basis and the related distribution on the 2% general partner
interest during those periods; and
(3) there are no arrearages in payment of the minimum quarterly
distribution on the common units.
Upon expiration of the subordination period, all remaining subordinated
units will convert into common units on a one-for-one basis and will then
participate, pro rata, with the other common units in distributions of
available cash. In addition, if the general partner is removed as general
partner of Plains All American Pipeline under circumstances where cause does
not exist and units held by the general partner and its affiliates are not
voted in favor of that removal:
(1) the subordination period will end and all outstanding subordinated
units will immediately convert into common units on a one-for-one basis;
(2) any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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(3) the general partner will have the right to convert its general
partner interests and its incentive distribution rights into common units
or to receive cash in exchange for those interests.
Limited Voting Rights
Holders of subordinated units will sometimes vote as a single class
together with the common units and sometimes vote as a class separate from the
holders of common units and, as in the case of holders of common units, will
have very limited voting rights. During the subordination period, common units
and subordinated units each vote separately as a class on the following
matters:
(1) a sale or exchange of all or substantially all of our assets;
(2) the election of a successor general partner in connection with the
removal of the general partner;
(3) dissolution or reconstitution;
(4) a merger;
(5) issuance of limited partner interests in some circumstances; and
(6) some amendments to the partnership agreement, including any
amendment that would cause us to be treated as an association taxable as a
corporation.
The subordinated units are not entitled to vote on approval of the
withdrawal of the general partner or the transfer by the general partner of
its general partner interest or incentive distribution rights under some
circumstances. Removal of the general partner requires:
. a two-thirds vote of all outstanding units voting as a single class; and
. the election of a successor general partner by the holders of a majority
of the outstanding common units and subordinated units, voting as
separate classes.
Under the partnership agreement, the general partner generally will be
permitted to effect amendments to the partnership agreement that do not
materially adversely affect unitholders without the approval of any
unitholders.
Distributions upon Liquidation
If we liquidate during the subordination period, in some circumstances
holders of outstanding common units will be entitled to receive more per unit
in liquidating distributions than holders of outstanding subordinated units.
The per unit difference will be dependent upon the amount of gain or loss that
we recognize in liquidating our assets. Following conversion of the
subordinated units into common units, all units will be treated the same upon
liquidation.
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THE PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of the Plains All
American Pipeline partnership agreement. The partnership agreement for each of
Plains Marketing, L.P., All American Pipeline, L.P. and Plains Scurlock
Permian, L.P. are included as exhibits to the registration statement of which
this prospectus constitutes a part. Plains All American Pipeline will provide
prospective investors with a copy of these agreements upon request at no
charge.
The following provisions of the partnership agreement are summarized
elsewhere in this prospectus.
. With regard to the transfer of common units, see "Description of the
Common Units--Transfer of Common Units."
. With regard to distributions of Available Cash, see "Cash Distribution
Policy."
. With regard to allocations of taxable income and taxable loss, see "Tax
Considerations."
Organization and Duration
Plains All American Pipeline was organized in September 1998. Plains All
American Pipeline will dissolve on December 31, 2088 unless sooner dissolved
under the terms of the partnership agreement.
Purpose
Our purpose under the partnership agreement is limited to serving as the
limited partner of Plains Marketing, L.P. and engaging in any business
activities that may be engaged in by Plains Marketing, L.P. or that is approved
by the general partner. The partnership agreement of Plains Marketing, L.P.
provides that Plains Marketing, L.P. may, directly or indirectly, engage in:
(1) its operations as conducted immediately before our initial public
offering;
(2) any other activity approved by the general partner but only to the
extent that the general partner reasonably determines that, as of the date
of the acquisition or commencement of the activity, the activity generates
"qualifying income" as this term is defined in Section 7704 of the Internal
Revenue Code; or
(3) any activity that enhances the operations of an activity that is
described in (1) or (2) above.
Although the general partner has the ability to cause Plains All American
Pipeline, the operating partnerships and the subsidiaries to engage in
activities other than the transportation, terminalling and storage and
gathering and marketing of crude oil, the general partner has no current plans
to do so. The general partner is authorized in general to perform all acts
deemed necessary to carry out our purposes and to conduct our business.
Power of Attorney
Each limited partner, and each person who acquires a unit from a unitholder
and executes and delivers a transfer application, grants to the general partner
and, if appointed, a liquidator, a power of attorney to, among other things,
execute and file documents required for the qualification, continuance or
dissolution of Plains All American Pipeline. The power of attorney also grants
the authority for the amendment of, and to make consents and waivers under, the
partnership agreement.
Capital Contributions
Unitholders are not obligated to make additional capital contributions,
except as described below under "--Limited Liability."
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Limited Liability
Assuming that a limited partner does not participate in the control of our
business within the meaning of the Delaware Revised Uniform Limited Partnership
Act and that he otherwise acts in conformity with the provisions of the
partnership agreement, his liability under the Delaware Act will be limited,
subject to possible exceptions, to the amount of capital he is obligated to
contribute to us for his common units plus his share of any undistributed
profits and assets. If it were determined, however, that the right or exercise
of the right by the limited partners as a group:
. to remove or replace the general partner;
. to approve some amendments to the partnership agreement; or
. to take other action under the partnership agreement;
constituted "participation in the control" of our business for the purposes of
the Delaware Act, then the limited partners could be held personally liable for
our obligations under the laws of Delaware, to the same extent as the general
partner. This liability would extend to persons who transact business with us
who reasonably believe that the limited partner is a general partner. Neither
the partnership agreement nor the Delaware Act specifically provides for legal
recourse against the general partner if a limited partner were to lose limited
liability through any fault of the general partner. While this does not mean
that a limited partner could not seek legal recourse, we have found no
precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to
a partner if after the distribution, all liabilities of the limited
partnership, other than liabilities to partners on account of their partnership
interests and liabilities for which the recourse of creditors is limited to
specific property of the partnership, exceed the fair value of the assets of
the limited partnership. For the purpose of determining the fair value of the
assets of a limited partnership, the Delaware Act provides that the fair value
of property subject to liability for which recourse of creditors is limited
shall be included in the assets of the limited partnership only to the extent
that the fair value of that property exceeds the nonrecourse liability. The
Delaware Act provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was in violation of
the Delaware Act shall be liable to the limited partnership for the amount of
the distribution for three years. Under the Delaware Act, an assignee who
becomes a substituted limited partner of a limited partnership is liable for
the obligations of his assignor to make contributions to the partnership,
except the assignee is not obligated for liabilities unknown to him at the time
he became a limited partner and which could not be ascertained from the
partnership agreement.
Our subsidiaries conduct business in twenty-three states. Maintenance of
limited liability for Plains All American Pipeline, as a limited partner of the
operating partnerships, may require compliance with legal requirements in the
jurisdictions in which the operating partnerships conduct business, including
qualifying our subsidiaries to do business there. Limitations on the liability
of limited partners for the obligations of a limited partner have not been
clearly established in many jurisdictions. If it were determined that we were,
by virtue of our limited partner interest in Plains Marketing, L.P. or
otherwise, conducting business in any state without compliance with the
applicable limited partnership or limited liability company statute, or that
the right or exercise of the right by the limited partners as a group to remove
or replace the general partner, to approve some amendments to the partnership
agreement, or to take other action under the partnership agreement constituted
"participation in the control" of our business for purposes of the statutes of
any relevant jurisdiction, then the limited partners could be held personally
liable for our obligations under the law of that jurisdiction to the same
extent as the general partner under the circumstances. We will operate in a
manner as the general partner considers reasonable and necessary or appropriate
to preserve the limited liability of the limited partners.
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Issuance of Additional Securities
The partnership agreement authorizes us to issue an unlimited number of
additional limited partner interests and other equity securities for the
consideration and on the terms and conditions established by the general
partner in its sole discretion without the approval of any limited partners.
During the subordination period, however, except as set forth in the following
paragraph, we may not issue equity securities ranking senior to the common
units or an aggregate of more than 10,030,000 additional common units or units
on a parity with the common units, in each case, without the approval of the
holders of a majority of the outstanding common units and subordinated units,
voting as separate classes.
During the subordination period or thereafter, we may issue an unlimited
number of common units as follows:
(1) upon exercise of the underwriter's over-allotment option;
(2) upon conversion of the subordinated units;
(3) under employee benefit plans;
(4) upon conversion of the general partner interests and incentive
distribution rights as a result of a withdrawal of the general partner;
(5) in the event of a combination or subdivision of common units;
(6) to finance an acquisition or a capital improvement that would have
resulted, on a pro forma basis, in an increase in Adjusted Operating
Surplus on a per unit basis for the preceding four-quarter period; or
(7) to repay up to $40 million of qualifying indebtedness.
It is possible that we will fund acquisitions through the issuance of
additional common units or other equity securities. Holders of any additional
common units we issue will be entitled to share equally with the then-existing
holders of common units in our distributions of Available Cash. In addition,
the issuance of additional partnership interests may dilute the value of the
interests of the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of the partnership
agreement, we may also issue additional partnership securities interests that,
in the sole discretion of the general partner, may have special voting rights
to which the common units are not entitled.
Upon issuance of additional partnership securities, the general partner will
be required to make additional capital contributions to the extent necessary to
maintain its combined 2% general partner interest in us, the operating
partnerships and the subsidiaries. Moreover, the general partner will have the
right, which it may from time to time assign in whole or in part to any of its
affiliates, to purchase common units, subordinated units or other equity
securities whenever, and on the same terms that, we issue those securities to
persons other than the general partner and its affiliates, to the extent
necessary to maintain their percentage interest, including their interest
represented by common units and subordinated units, that existed immediately
prior to each issuance. The holders of common units will not have preemptive
rights to acquire additional common units or other partnership interests.
Amendment of the Partnership Agreement
Amendments to the partnership agreement may be proposed only by or with the
consent of the general partner, which consent may be given or withheld in its
sole discretion. In order to adopt a proposed amendment, other than the
amendments discussed below, the general partner is required to seek written
approval of the holders of the number of units required to approve the
amendment or call a meeting of the limited partners to consider and vote upon
the proposed amendment except as described below.
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Prohibited Amendments. No amendment may be made that would:
(1) enlarge the obligations of any limited partner without its consent,
unless approved by at least a majority of the type or class of limited
partner interests so affected;
(2) enlarge the obligations of, restrict in any way any action by or
rights of, or reduce in any way the amounts distributable, reimbursable or
otherwise payable by Plains All American Pipeline to the general partner or
any of its affiliates without their consent, which may be given or withheld
in their sole discretion;
(3) change the term of Plains All American Pipeline;
(4) provide that Plains All American Pipeline is not dissolved upon the
expiration of its term or upon an election to dissolve Plains All American
Pipeline by the general partner that is approved by the holders of a
majority of the outstanding common units and subordinated units, voting as
separate classes; or
(5) give any person the right to dissolve Plains All American Pipeline
other than the general partner's right to dissolve Plains All American
Pipeline with the approval of the holders of a majority of the outstanding
common units and subordinated units, voting as separate classes.
The provision of the partnership agreement preventing the amendments having the
effects described in clauses (1)-(5) above can be amended upon the approval of
the holders of at least 90% of the outstanding units voting together as a
single class.
No Unitholder Approval. The general partner may generally make amendments to
the partnership agreement without the approval of any limited partner or
assignee to reflect:
(1) a change in the name of Plains All American Pipeline, the location
of the principal place of business of Plains All American Pipeline, the
registered agent or the registered office of Plains All American Pipeline;
(2) the admission, substitution, withdrawal or removal of partners in
accordance with the partnership agreement;
(3) a change that, in the sole discretion of the general partner, is
necessary or advisable to qualify or continue the qualification of Plains
All American Pipeline as a limited partnership or a partnership in which
the limited partners have limited liability under the laws of any state or
to ensure that none of Plains All American Pipeline, the operating
partnerships nor the subsidiaries will be treated as an association taxable
as a corporation or otherwise taxed as an entity for federal income tax
purposes;
(4) an amendment that is necessary, in the opinion of counsel to Plains
All American Pipeline, to prevent Plains All American Pipeline or the
general partner or its directors, officers, agents or trustees, from in any
manner being subjected to the provisions of the Investment Company Act of
1940, the Investment Advisors Act of 1940, or "plan asset" regulations
adopted under the Employee Retirement Income Security Act of 1974, whether
or not substantially similar to plan asset regulations currently applied or
proposed;
(5) subject to the limitations on the issuance of additional common
units or other limited or general partner interests described above, an
amendment that in the discretion of the general partner is necessary or
advisable for the authorization of additional limited or general partner
interests;
(6) any amendment expressly permitted in the partnership agreement to be
made by the general partner acting alone;
(7) an amendment effected, necessitated or contemplated by a merger
agreement that has been approved under the terms of the partnership
agreement;
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(8) any amendment that, in the discretion of the general partner, is
necessary or advisable for the formation by Plains All American Pipeline
of, or its investment in, any corporation, partnership or other entity, as
otherwise permitted by the partnership agreement;
(9) a change in the fiscal year or taxable year of Plains All American
Pipeline and related changes; and
(10) any other amendments substantially similar to any of the matters
described in (1)-(9) above.
In addition, the general partner may make amendments to the partnership
agreement without the approval of any limited partner or assignee if those
amendments, in the discretion of the general partner:
(1) do not adversely affect the limited partners in any material
respect;
(2) are necessary or advisable to satisfy any requirements, conditions
or guidelines contained in any opinion, directive, order, ruling or
regulation of any federal or state agency or judicial authority or
contained in any federal or state statute;
(3) are necessary or advisable to facilitate the trading of limited
partner interests or to comply with any rule, regulation, guideline or
requirement of any securities exchange on which the limited partner
interests are or will be listed for trading, compliance with any of which
the general partner deems to be in the best interests of Plains All
American Pipeline and the limited partners;
(4) are necessary or advisable for any action taken by the general
partner relating to splits or combinations of units under the provisions of
the partnership agreement; or
(5) are required to effect the intent expressed in this prospectus or
the intent of the provisions of the partnership agreement or are otherwise
contemplated by the partnership agreement.
Opinion of Counsel and Unitholder Approval. The general partner will not be
required to obtain an opinion of counsel that an amendment will not result in
a loss of limited liability to the limited partners or result in Plains All
American Pipeline being treated as an entity for federal income tax purposes
if one of the amendments described above under "--No Unitholder Approval"
should occur. No other amendments to the partnership agreement will become
effective without the approval of holders of at least 90% of the units unless
Plains All American Pipeline obtains an opinion of counsel to the effect that
the amendment will not affect the limited liability under applicable law of
any limited partner in Plains All American Pipeline or cause Plains All
American Pipeline, the operating partnerships or the subsidiaries to be
taxable as a corporation or otherwise to be taxed as an entity for federal
income tax purposes (to the extent not previously taxed as such).
Any amendment that would have a material adverse effect on the rights or
preferences of any type or class of outstanding units in relation to other
classes of units will require the approval of at least a majority of the type
or class of units so affected. Any amendment that reduces the voting
percentage required to take any action is required to be approved by the
affirmative vote of limited partners constituting not less than the voting
requirement sought to be reduced.
Merger, Sale or Other Disposition of Assets
The general partner is generally prohibited, without the prior approval of
the holders of a majority of the outstanding common units and subordinated
units, voting as separate classes, from causing Plains All American Pipeline
to, among other things, sell, exchange or otherwise dispose of all or
substantially all of its assets in a single transaction or a series of related
transactions, including by way of merger, consolidation or other combination,
or approving on behalf of Plains All American Pipeline the sale, exchange or
other disposition of all or substantially all of the assets of the
subsidiaries; provided that the general partner may mortgage, pledge,
hypothecate or grant a security interest in all or substantially all of Plains
All American Pipeline's assets without that approval. The general partner may
also sell all or substantially all of Plains All American Pipeline's assets
under a foreclosure or other realization upon the encumbrances above without
that approval.
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Furthermore, provided that conditions specified in the partnership agreement
are satisfied, the general partner may merge Plains All American Pipeline or
any of its subsidiaries into, or convey some or all of their assets to, a newly
formed entity if the sole purpose of that merger or conveyance is to effect a
mere change in the legal form of Plains All American Pipeline into another
limited liability entity. The unitholders are not entitled to dissenters'
rights of appraisal under the partnership agreement or applicable Delaware law
in the event of a merger or consolidation, a sale of substantially all of
Plains All American Pipeline's assets or any other transaction or event.
Termination and Dissolution
We will continue until December 31, 2088, unless terminated sooner under the
partnership agreement. We will dissolve upon:
(1) the election of the general partner to dissolve us, if approved by
the holders of a majority of the outstanding common units and subordinated
units, voting as separate classes;
(2) the sale, exchange or other disposition of all or substantially all
of the assets and properties of Plains All American Pipeline and the
subsidiaries;
(3) the entry of a decree of judicial dissolution of Plains All American
Pipeline; or
(4) the withdrawal or removal of the general partner or any other event
that results in its ceasing to be the general partner other than by reason
of a transfer of its general partner interest in accordance with the
partnership agreement or withdrawal or removal following approval and
admission of a successor.
Upon a dissolution under clause (4), the holders of a majority of the
outstanding common units and subordinated units, voting as separate classes,
may also elect, within specific time limitations, to reconstitute Plains All
American Pipeline and continue its business on the same terms and conditions
described in the partnership agreement by forming a new limited partnership on
terms identical to those in the partnership agreement and having as general
partner an entity approved by the holders of a majority of the outstanding
common units and subordinated units, voting as separate classes, subject to
receipt by Plains All American Pipeline of an opinion of counsel to the effect
that:
(1) the action would not result in the loss of limited liability of any
limited partner, and
(2) neither Plains All American Pipeline, the reconstituted limited
partnership, nor either of the subsidiaries would be treated as an
association taxable as a corporation or otherwise be taxable as an entity
for federal income tax purposes upon the exercise of that right to
continue.
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continued as a new
limited partnership, the liquidator authorized to wind up our affairs will,
acting with all of the powers of the general partner that the liquidator deems
necessary or desirable in its judgment, liquidate our assets and apply the
Proceeds of the liquidation as provided in "Cash Distribution Policy--
Distributions of Cash upon Liquidation." The liquidator may defer liquidation
or distribution of our assets for a reasonable period of time or distribute
assets to partners in kind if it determines that a sale would be impractical or
would cause undue loss to the partners.
Withdrawal or Removal of the General Partner
Except as described below, our general partner has agreed not to withdraw
voluntarily as general partner of either Plains All American Pipeline or the
operating partnerships prior to December 31, 2008 without obtaining the
approval of the holders of at least a majority of the outstanding common units,
excluding common units held by the general partner and its affiliates, and
furnishing an opinion of counsel regarding limited liability and tax matters.
On or after December 31, 2008, our general partner may withdraw as general
partner without first obtaining approval of any unitholder by giving 90 days'
written notice, and that
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withdrawal will not constitute a violation of the partnership agreement.
Notwithstanding the information above, our general partner may withdraw without
unitholder approval upon 90 days' notice to the limited partners if at least
50% of the outstanding common units are held or controlled by one person and
its affiliates other than the general partner and its affiliates. In addition,
the partnership agreement permits the general partner in some instances to sell
or otherwise transfer all of their general partner interests in Plains All
American Pipeline without the approval of the unitholders. See "--Transfer of
General Partner Interest and Incentive Distribution Rights."
Upon the withdrawal of the general partner under any circumstances, other
than as a result of a transfer by the general partner of all or a part of its
general partner interest in Plains All American Pipeline, the holders of a
majority of the outstanding common units and subordinated units, voting as
separate classes, may select a successor to that withdrawing general partner.
If a successor is not elected, or is elected but an opinion of counsel
regarding limited liability and tax matters cannot be obtained, Plains All
American Pipeline will be dissolved, wound up and liquidated, unless within 180
days after that withdrawal, the holders of a majority of the outstanding common
units and subordinated units, voting as separate classes, agree in writing to
continue the business of Plains All American Pipeline and to appoint a
successor general partner. See "--Termination and Dissolution."
The general partner may not be removed unless that removal is approved by
the vote of the holders of not less than 66 2/3% of the outstanding units,
including units held by the general partner and its affiliates, and Plains All
American Pipeline receives an opinion of counsel regarding limited liability
and tax matters. Any removal of the general partner is also subject to the
approval of a successor general partner by the vote of the holders of a
majority of the outstanding common units and subordinated units, voting as
separate classes.
The partnership agreement also provides that if the general partner is
removed as a general partner of Plains All American Pipeline under
circumstances where cause does not exist and units held by the general partner
and its affiliates are not voted in favor of that removal:
(1) the subordination period will end and all outstanding subordinated
units will immediately convert into common units on a one-for-one basis;
(2) any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
(3) the general partner will have the right to convert its general
partner interest and its incentive distribution rights into common units or
to receive cash in exchange for those interests.
Withdrawal or removal of the general partner as a general partner of Plains
All American Pipeline also constitutes withdrawal or removal, as the case may
be, of the general partner as the general partner of the operating partnerships
and as managing member of each of the subsidiaries.
In the event of removal of a general partner under circumstances where cause
exists or withdrawal of a general partner where that withdrawal violates the
partnership agreement, a successor general partner will have the option to
purchase the general partner interests and incentive distribution rights of the
departing general partner for a cash payment equal to the fair market value of
those interests. Under all other circumstances where a general partner
withdraws or is removed by the limited partners, the departing general partner
will have the option to require the successor general partner to purchase the
general partner interests of the departing general partner and its incentive
distribution rights for the fair market value. In each case, this fair market
value will be determined by agreement between the departing general partner and
the successor general partner. If no agreement is reached, an independent
investment banking firm or other independent expert selected by the departing
general partner and the successor general partner will determine the fair
market value. Or, if the departing general partner and the successor general
partner cannot agree upon an expert, then an expert chosen by agreement of the
experts selected by each of them will determine the fair market value.
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If the above-described option is not exercised by either the departing
general partner or the successor general partner, the departing general
partner's general partner interest and its incentive distribution rights will
automatically convert into common units equal to the fair market value of those
interests as determined by an investment banking firm or other independent
expert selected in the manner described in the preceding paragraph.
In addition, Plains All American Pipeline will be required to reimburse the
departing general partner for all amounts due the departing general partner,
including, without limitation, all employee-related liabilities, including
severance liabilities, incurred for the termination of any employees employed
by the departing general partner for the benefit of Plains All American
Pipeline.
Transfer of General Partner Interests and Incentive Distribution Rights
Except for transfer by either general partner of all, but not less than all,
of its general partner interests in Plains All American Pipeline and the
operating partnerships:
(a) an affiliate of either general partner, or
(b) another person as part of the merger or consolidation of either of
the general partner with or into another person or the transfer by either
of the general partner of all or substantially all of their assets to
another person,
the general partner may not transfer all or any part of their general partner
interest in Plains All American Pipeline and the operating partnerships and the
managing interest in each of the subsidiaries to another person prior to
December 31, 2008, without the approval of the holders of at least a majority
of the outstanding common units, excluding common units held by the general
partner and its affiliates. As a condition of this transfer, the transferee
must assume the rights and duties of the general partner to whose interest that
transferee has succeeded, agree to be bound by the provisions of the
partnership agreement, furnish an opinion of counsel regarding limited
liability and tax matters, agree to acquire all of the general partner's
interests in the operating partnerships and managing interest in each of the
subsidiaries and agree to be bound by the provisions of the limited liability
company agreements of the subsidiaries. The general partner and its affiliates
may at any time, however, transfer common units and subordinated units to one
or more persons, without unitholder approval, except that they may not transfer
subordinated units to Plains All American Pipeline. At any time, the
shareholder(s) of the general partner may sell or transfer all or part of their
shares in the general partner to an affiliate without the approval of the
unitholders. The general partner or its affiliates or a later holder may
transfer its incentive distribution rights to an affiliate or another person as
part of its merger or consolidation with or into, or sale of all or
substantially all of its assets to, that person without the prior approval of
the unitholders; provided that, in each case, the transferee agrees to be bound
by the provisions of the partnership agreement. Prior to December 31, 2008,
other transfers of the incentive distribution rights will require the
affirmative vote of holders of a majority of the outstanding common units and
subordinated units, voting as separate classes. On or after December 31, 2008,
the incentive distribution rights will be freely transferable.
Change of Management Provisions
The partnership agreement contains specific provisions that are intended to
discourage a person or group from attempting to remove Plains All American Inc.
as general partner of Plains All American Pipeline or otherwise change
management. If any person or group other than the general partner and its
affiliates acquires beneficial ownership of 20% or more of any class of units,
that person or group loses voting rights on all of its units. This loss of
voting rights does not apply to any person or group that acquires the units
from our general partner or its affiliates and any transferees of that person
or group approved by our general partner.
The partnership agreement also provides that if the general partner is
removed under circumstances where cause does not exist and units held by the
general partner and its affiliates are not voted in favor of that removal:
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(1) the subordination period will end and all outstanding subordinated
units will immediately convert into common units on a one-for-one basis;
(2) any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
(3) the general partner will have the right to convert its general
partner interest and its incentive distribution rights into common units or
to receive cash in exchange for those interests.
Limited Call Right
If at any time not more than 20% of the then-issued and outstanding limited
partner interests of any class are held by persons other than the general
partner and its affiliates, the general partner will have the right, which it
may assign in whole or in part to any of its affiliates or to Plains All
American Pipeline, to acquire all, but not less than all, of the remaining
limited partner interests of the class held by unaffiliated persons as of a
record date to be selected by the general partner, on at least 10 but not more
than 60 days' notice. The purchase price in the event of this purchase is the
greater of:
(1) the highest cash price paid by either of the general partner or any
of its affiliates for any limited partner interests of the class purchased
within the 90 days preceding the date on which the general partner first
mails notice of its election to purchase those limited partner interests;
and
(2) the current market price as of the date three days before the date
the notice is mailed.
As a result of the general partner's right to purchase outstanding limited
partner interests, a holder of limited partner interests may have his limited
partner interests purchased at an undesirable time or price. The tax
consequences to a unitholder of the exercise of this call right are the same as
a sale by that unitholder of his common units in the market. See "Tax
Considerations--Disposition of Common Units."
Meetings; Voting
Except as described below regarding a person or group owning 20% or more of
any class of units then outstanding, unitholders or assignees who are record
holders of units on the record date will be entitled to notice of, and to vote
at, meetings of limited partners of Plains All American Pipeline and to act
upon matters for which approvals may be solicited. Common units that are owned
by an assignee who is a record holder, but who has not yet been admitted as a
limited partner, shall be voted by the general partner at the written direction
of the record holder. Absent direction of this kind, the common units will not
be voted, except that, in the case of common units held by the general partner
on behalf of non-citizen assignees, the general partner shall distribute the
votes on those common units in the same ratios as the votes of limited partners
on other units are cast.
Any action that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a meeting if
consents in writing describing the action so taken are signed by holders of the
number of units as would be necessary to authorize or take that action at a
meeting. Meetings of the unitholders may be called by the general partner or by
unitholders owning at least 20% of the outstanding units of the class for which
a meeting is proposed. Unitholders may vote either in person or by proxy at
meetings. The holders of a majority of the outstanding units of the class or
classes for which a meeting has been called represented in person or by proxy
shall constitute a quorum unless any action by the unitholders requires
approval by holders of a greater percentage of the units, in which case the
quorum shall be the greater percentage.
Each record holder of a unit has a vote according to his percentage interest
in Plains All American Pipeline, although additional limited partner interests
having special voting rights could be issued. See "--Issuance of Additional
Securities." However, if at any time any person or group, other than the
general partner and its affiliates, or a direct or subsequently approved
transferee of the general partner or its affiliates,
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acquires, in the aggregate, beneficial ownership of 20% or more of any class of
units then outstanding, the person or group will lose voting rights on all of
its units and the units may not be voted on any matter and will not be
considered to be outstanding when sending notices of a meeting of unitholders,
calculating required votes, determining the presence of a quorum or for other
similar purposes. Common units held in nominee or street name account will be
voted by the broker or other nominee in accordance with the instruction of the
beneficial owner unless the arrangement between the beneficial owner and his
nominee provides otherwise. Except as otherwise provided in the partnership
agreement, subordinated units will vote together with common units as a single
class.
Any notice, demand, request, report or proxy material required or permitted
to be given or made to record holders of common units under the partnership
agreement will be delivered to the record holder by Plains All American
Pipeline or by the transfer agent.
Status as Limited Partner or Assignee
Except as described above under "--Limited Liability," the common units will
be fully paid, and unitholders will not be required to make additional
contributions.
An assignee of a common unit, after executing and delivering a transfer
application, but pending its admission as a substituted limited partner, is
entitled to an interest equivalent to that of a limited partner for the right
to share in allocations and distributions from Plains All American Pipeline,
including liquidating distributions. The general partner will vote and exercise
other powers attributable to common units owned by an assignee who has not
become a substitute limited partner at the written direction of the assignee.
See "--Meetings; Voting." Transferees who do not execute and deliver a transfer
application will be treated neither as assignees nor as record holders of
common units, and will not receive cash distributions, federal income tax
allocations or reports furnished to holders of common units. See "Description
of the Common Units--Transfer of Common Units."
Non-citizen Assignees; Redemption
If we are or become subject to federal, state or local laws or regulations
that, in the reasonable determination of the general partner, create a
substantial risk of cancellation or forfeiture of any property that we have an
interest in because of the nationality, citizenship or other related status of
any limited partner or assignee, we may redeem the units held by the limited
partner or assignee at their current market price. In order to avoid any
cancellation or forfeiture, the general partner may require each limited
partner or assignee to furnish information about his nationality, citizenship
or related status. If a limited partner or assignee fails to furnish
information about this nationality, citizenship or other related status within
30 days after a request for the information or the general partner determines
after receipt of the information that the limited partner or assignee is not an
eligible citizen, the limited partner or assignee may be treated as a non-
citizen assignee. In addition to other limitations on the rights of an assignee
who is not a substituted limited partner, a non-citizen assignee does not have
the right to direct the voting of his units and may not receive distributions
in kind upon our liquidation.
Indemnification
Under the partnership agreement, in most circumstances, we will indemnify
the following persons, to the fullest extent permitted by law, from and against
all losses, claims, damages or similar events:
(1) the general partner;
(2) any departing general partner,
(3) any person who is or was an affiliate of a general partner or any
departing general partner,
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(4) any person who is or was a member, partner, officer, director,
employee, agent or trustee of a general partner or any departing general
partner or any affiliate of a general partner or any departing general
partner; or
(5) any person who is or was serving at the request of a general partner
or any departing general partner or any affiliate of a general partner or
any departing general partner as an officer, director, employee, member,
partner, agent or trustee of another person.
Any indemnification under these provisions will only be out of our assets.
The general partner shall not be personally liable for, or have any obligation
to contribute or loan funds or assets to us to enable us to effectuate
indemnification. We are authorized to purchase insurance against liabilities
asserted against and expenses incurred by persons for our activities,
regardless of whether we would have the power to indemnify the person against
liabilities under the partnership agreement.
Books and Reports
The general partner is required to keep appropriate books of our business at
our principal offices. The books will be maintained for both tax and financial
reporting purposes on an accrual basis. For tax and fiscal reporting purposes,
our fiscal year is the calendar year.
We will furnish or make available to record holders of common units, within
120 days after the close of each fiscal year, an annual report containing
audited financial statements and a report on those financial statements by our
independent public accountants. Except for our fourth quarter, we will also
furnish or make available summary financial information within 90 days after
the close of each quarter.
We will furnish each record holder of a unit with information reasonably
required for tax reporting purposes within 90 days after the close of each
calendar year. This information is expected to be furnished in summary form so
that some complex calculations normally required of partners can be avoided.
Our ability to furnish this summary information to unitholders will depend on
the cooperation of unitholders in supplying us with specific information. Every
unitholder will receive information to assist him in determining his federal
and state tax liability and filing his federal and state income tax returns,
regardless of whether he supplies us with information.
Right to Inspect Our Books and Records
The partnership agreement provides that a limited partner can, for a purpose
reasonably related to his interest as a limited partner, upon reasonable demand
and at his own expense, have furnished to him:
(1) a current list of the name and last known address of each partner;
(2) a copy of our tax returns;
(3) information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on which each
became a partner;
(4) copies of the partnership agreement, the certificate of limited
partnership of the partnership, related amendments and powers of attorney
under which they have been executed;
(5) information regarding the status of our business and financial
condition; and
(6) any other information regarding our affairs as is just and
reasonable.
The general partner may, and intends to, keep confidential from the limited
partners trade secrets or other information the disclosure of which the general
partner believes in good faith is not in our best interests or which we are
required by law or by agreements with third parties to keep confidential.
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Registration Rights
Under the partnership agreement, we have agreed to register for resale under
the Securities Act and applicable state securities laws any common units,
including any common units to be issued upon the conversion of the Class B
common units, subordinated units or other partnership securities proposed to be
sold by the general partner or any of its affiliates or their assignees if an
exemption from the registration requirements is not otherwise available. These
registration rights continue for two years following any withdrawal or removal
of our general partner as the general partner of Plains All American Pipeline.
We are obligated to pay all expenses incidental to the registration, excluding
underwriting discounts and commissions. See "Units Eligible for Future Sale."
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UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered hereby, the general partner will
hold 8,281,429 common units, including 1,307,190 Class B common units and
10,029,619 subordinated units. The Class B common units may be converted into
common units with the approval of a majority of the common units voting at a
meeting of unitholders. All of these subordinated units will convert into
common units at the end of the subordination period and some may convert
earlier. The sale of these units could have an adverse impact on the price of
the common units or on any trading market that may develop.
The common units sold in the offering will generally be freely transferable
without restriction or further registration under the Securities Act, except
that any common units owned by an "affiliate" of Plains All American Pipeline
may not be resold publicly except in compliance with the registration
requirements of the Securities Act or under an exemption under Rule 144 or
otherwise. Rule 144 permits securities acquired by an affiliate of the issuer
to be sold into the market in an amount that does not exceed, during any three-
month period, the greater of:
(1) 1% of the total number of the securities outstanding; or
(2) the average weekly reported trading volume of the common units for
the four calendar weeks prior to the sale.
Sales under Rule 144 are also subject to specific manner of sale provisions,
notice requirements and the availability of current public information about
Plains All American Pipeline. A person who is not deemed to have been an
affiliate of Plains All American Pipeline at any time during the three months
preceding a sale, and who has beneficially owned his common units for at least
two years, would be entitled to sell common units under Rule 144 without regard
to the public information requirements, volume limitations, manner of sale
provisions and notice requirements of Rule 144.
Prior to the end of the subordination period, Plains All American Pipeline
may not issue equity securities of the partnership ranking prior or senior to
the common units or an aggregate of more than 10,030,000 additional common
units or an equivalent amount of securities ranking on a parity with the common
units, without the approval of the holders of a majority of the outstanding
common units and subordinated units, voting as separate classes. The 10,030,000
number is subject to adjustment in the event of a combination or subdivision of
common units and shall exclude common units issued:
. upon exercise of the underwriters' over-allotment option;
. upon conversion of subordinated units;
. in connection with Plains All American Pipeline's making acquisitions or
capital improvements that are accretive to our cash flow on a per-unit
basis;
. to repay up to $40 million of qualifying indebtedness;
. under an employee benefit plan; or
. upon conversion of the general partner interests and incentive
distribution rights as a result of the withdrawal of the general partner.
The partnership agreement provides that, after the subordination period,
Plains All American Pipeline may issue an unlimited number of limited partner
interests of any type without a vote of the unitholders. The partnership
agreement does not restrict Plains All American Pipeline's ability to issue
equity securities ranking junior to the common units at any time. Any issuance
of additional common units or other equity securities would result in a
corresponding decrease in the proportionate ownership interest in Plains All
American Pipeline represented by, and could adversely affect the cash
distributions to and market price of, common units then outstanding. See "The
Partnership Agreement--Issuance of Additional Securities."
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Under the partnership agreement, the general partner and its affiliates have
the right to cause Plains All American Pipeline to register under the
Securities Act and state laws the offer and sale of any units that they hold.
Subject to the terms and conditions of the partnership agreement, these
registration rights allow the general partner and its affiliates or their
assignees holding any units to require registration of any of these units and
to include any of these units in a registration by Plains All American Pipeline
of other units, including units offered by Plains All American Pipeline or by
any unitholder. The general partner will continue to have these registration
rights for two years following its withdrawal or removal as the general partner
of Plains All American Pipeline. In connection with any registration of this
kind, Plains All American Pipeline will indemnify each unitholder participating
in the registration and its officers, directors and controlling persons from
and against any liabilities under the Securities Act or any state securities
laws arising from the registration statement or prospectus. Plains All American
Pipeline will bear all costs and expenses incidental to any registration,
excluding any underwriting discounts and commissions. Except as described
below, the general partner and its affiliates may sell their units in private
transactions at any time, subject to compliance with applicable laws.
Plains Resources, Plains All American Pipeline, various subsidiaries, the
general partner and the officers and directors of the general partner have
agreed that, for a period of 90 days from the date of this prospectus, they
will not, without the prior written consent of Salomon Smith Barney Inc.,
dispose of or hedge any common units or subordinated units of Plains All
American Pipeline or any securities convertible into or exchangeable for, or
that represent the right to receive, common units or subordinated units or any
securities that are senior to or on a parity with common units or grant any
options or warrants to purchase common units or subordinated units, other than
pursuant to our long-term incentive plan. This restriction will not prohibit
our issuance of common units in connection with acquisitions and capital
improvements which are accretive on a per unit basis in accordance with the
terms of our partnership agreement.
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TAX CONSIDERATIONS
This section is a summary of the material tax considerations that may be
relevant to prospective unitholders who are individual citizens or residents of
the United States and, to the extent set forth below under "--Legal Opinions
and Advice," expresses the opinion of Andrews & Kurth L.L.P., special counsel
to the general partner and us, insofar as it relates to matters of United
States federal income tax law and legal conclusions with respect thereto. This
section is based upon current provisions of the Internal Revenue Code, existing
and proposed regulations and current administrative rulings and court
decisions, all of which are subject to change. Later changes in these
authorities may cause the tax consequences to vary substantially from the
consequences described below. Unless the context otherwise requires, references
in this section to us are references to Plains All American Pipeline and the
operating partnerships.
No attempt has been made in the following discussion to comment on all
federal income tax matters affecting us or the unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or residents of
the United States and has only limited application to corporations, estates,
trusts, nonresident aliens or other unitholders subject to specialized tax
treatment, such as tax-exempt institutions, foreign persons, IRAs, REITs or
mutual funds. Accordingly, each prospective unitholder should consult, and
should depend on, his own tax advisor in analyzing the federal, state, local
and foreign tax consequences to him of the ownership or disposition of common
units.
Legal Opinions and Advice
Counsel is of the opinion that, based on the accuracy of representations and
covenants and subject to the qualifications set forth in the detailed
discussion that follows, for federal income tax purposes:
(1) Plains All American Pipeline and the operating partnerships will
each be treated as a partnership; and
(2) owners of common units, with some exceptions, as described in "--
Limited Partner Status" below, will be treated as partners of Plains All
American Pipeline, but not of the operating partnerships.
In addition, all statements as to matters of law and legal conclusions
contained in this section, unless otherwise noted, are the opinion of counsel.
No ruling has been or will be requested from the IRS regarding our
classification as a partnership for federal income tax purposes, whether our
operations generate "qualifying income" under Section 7704 of the Internal
Revenue Code or any other matter affecting us or prospective unitholders. An
opinion of counsel represents only that counsel's best legal judgment and does
not bind the IRS or the courts. Accordingly, we cannot assure you that the
opinions and statements made here would be sustained by a court if contested by
the IRS. Any contest of this sort with the IRS may materially and adversely
impact the market for the common units and the prices at which common units
trade. In addition, the costs of any contest with the IRS will be borne
directly or indirectly by the unitholders and the general partner. Furthermore,
we cannot assure you that the treatment of Plains All American Pipeline, or an
investment in Plains All American Pipeline, will not be significantly modified
by future legislative or administrative changes or court decisions. Any
modifications may or may not be retroactively applied.
For the reasons described below, counsel has not rendered an opinion with
respect to the following specific federal income tax issues:
(1) the treatment of a unitholder whose common units are loaned to a
short seller to cover a short sale of common units (see "--Tax Consequences
of Unit Ownership--Treatment of Short Sales");
(2) whether a unitholder acquiring common units in separate transactions
must maintain a single aggregate adjusted tax basis in his common units
(see "--Disposition of Common Units--Recognition of Gain or Loss");
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(3) whether our monthly convention for allocating taxable income and
losses is permitted by existing Treasury Regulations (see "--Disposition of
Common Units--Allocations Between Transferors and Transferees"); and
(4) whether our method for depreciating Section 743 adjustments is
sustainable (see "--Tax Consequences of Unit Ownership--Section 754
Election").
Partnership Status
A partnership is not a taxable entity and incurs no federal income tax
liability. Instead, each partner of a partnership is required to take into
account his allocable share of items of income, gain, loss and deduction of
the partnership in computing his federal income tax liability, regardless of
whether cash distributions are made. Distributions by a partnership to a
partner are generally not taxable unless the amount of cash distributed is in
excess of the partner's adjusted basis in his partnership interest.
No ruling has been or will be sought from the IRS and the IRS has made no
determination as to the status of Plains All American Pipeline or the
operating partnerships as partnerships for federal income tax purposes.
Instead, we have relied on the opinion of counsel that, based upon the
Internal Revenue Code, its regulations, published revenue rulings and court
decisions and the representations described below, each of Plains All American
Pipeline and the operating partnerships will be classified as a partnership
for federal income tax purposes.
In rendering its opinion, counsel has relied on factual representations and
covenants made by us and the general partner. The representations and
covenants made by us and our general partner upon which counsel has relied
are:
(a) None of Plains All American Pipeline or the operating partnerships
will elect to be treated as an association or corporation;
(b) Plains All American Pipeline and the operating partnerships will be
operated in accordance with
(1) all applicable partnership statutes,
(2) the applicable partnership agreement, and
(3) their description in this prospectus;
(c) For each taxable year, more than 90% of our gross income will be
income from sources that our counsel has or will opine is "qualifying
income" within the meaning of Section 7704(d) of the Internal Revenue Code.
Section 7704 of the Internal Revenue Code provides that publicly-traded
partnerships will, as a general rule, be taxed as corporations. However, an
exception, referred to as the "Qualifying Income Exception," exists with
respect to publicly-traded partnerships of which 90% or more of the gross
income for every taxable year consists of "qualifying income." Qualifying
income includes income and gains derived from the transportation and marketing
of crude oil, natural gas and products thereof. Other types of qualifying
income include interest (from other than a financial business), dividends,
gains from the sale of real property and gains from the sale or other
disposition of capital assets held for the production of income that otherwise
constitutes qualifying income. We estimate that less than 3% of our current
income is not qualifying income; however, this estimate could change from time
to time. Based upon and subject to this estimate, the factual representations
made by us and the general partner and a review of the applicable legal
authorities, counsel is of the opinion that at least 90% of our gross income
will constitute qualifying income.
If we fail to meet the Qualifying Income Exception, other than a failure
which is determined by the IRS to be inadvertent and which is cured within a
reasonable time after discovery, we will be treated as if we had transferred
all of our assets, subject to liabilities, to a newly formed corporation, on
the first day of the year in
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which we fail to meet the Qualifying Income Exception, in return for stock in
that corporation, and then distributed that stock to the partners in
liquidation of their interests in us. This contribution and liquidation should
be tax-free to unitholders and Plains All American Pipeline so long as we, at
that time, do not have liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal income tax
purposes.
If we were taxable as a corporation in any taxable year, either as a result
of a failure to meet the Qualifying Income Exception or otherwise, our items of
income, gain, loss and deduction would be reflected only on our tax return
rather than being passed through to the unitholders, and our net income would
be taxed to us or the operating partnerships at corporate rates. In addition,
any distribution made to a unitholder would be treated as either taxable
dividend income, to the extent of our current or accumulated earnings and
profits, or, in the absence of earnings and profits, a nontaxable return of
capital, to the extent of the unitholder's tax basis in his common units, or
taxable capital gain, after the unitholder's tax basis in his common units is
reduced to zero. Accordingly, taxation as a corporation would result in a
material reduction in a unitholder's cash flow and after-tax return and thus
would likely result in a substantial reduction of the value of the units.
The discussion below is based on the assumption that we will be classified
as a partnership for federal income tax purposes.
Limited Partner Status
Unitholders who have become limited partners of Plains All American Pipeline
will be treated as partners of Plains All American Pipeline for federal income
tax purposes. Counsel is also of the opinion that
(a) assignees who have executed and delivered transfer applications, and
are awaiting admission as limited partners, and
(b) unitholders whose common units are held in street name or by a
nominee and who have the right to direct the nominee in the exercise of all
substantive rights attendant to the ownership of their common units,
will be treated as partners of Plains All American Pipeline for federal income
tax purposes. As there is no direct authority addressing assignees of common
units who are entitled to execute and deliver transfer applications and thereby
become entitled to direct the exercise of attendant rights, but who fail to
execute and deliver transfer applications, counsel's opinion does not extend to
these persons. Furthermore, a purchaser or other transferee of common units who
does not execute and deliver a transfer application may not receive some
federal income tax information or reports furnished to record holders of common
units unless the common units are held in a nominee or street name account and
the nominee or broker has executed and delivered a transfer application for
those common units.
A beneficial owner of common units whose units have been transferred to a
short seller to complete a short sale would appear to lose his status as a
partner with respect to these units for federal income tax purposes. See "--Tax
Consequences of Unit Ownership--Treatment of Short Sales."
Income, gain, deductions or losses would not appear to be reportable by a
unitholder who is not a partner for federal income tax purposes, and any cash
distributions received by a unitholder who is not a partner for federal income
tax purposes would therefore be fully taxable as ordinary income. These holders
should consult their own tax advisors with respect to their status as partners
in Plains All American Pipeline for federal income tax purposes.
Tax Consequences of Unit Ownership
Flow-through of Taxable Income. We will not pay any federal income tax.
Instead, each unitholder will be required to report on his income tax return
his allocable share of our income, gains, losses and deductions
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without regard to whether corresponding cash distributions are received by that
unitholder. Consequently, we may allocate income to a unitholder even if he has
not received a cash distribution. Each unitholder will be required to include
in income his allocable share of Plains All American Pipeline income, gain,
loss and deduction for the taxable year of Plains All American Pipeline ending
with or within the taxable year of the unitholder.
Treatment of Distributions. Distributions by us to a unitholder generally
will not be taxable for federal income tax purposes to the extent of his tax
basis in his common units immediately before the distribution. Our cash
distributions in excess of a unitholder's tax basis generally will be
considered to be gain from the sale or exchange of the common units, taxable in
accordance with the rules described under "--Disposition of Common Units"
below. Any reduction in a unitholder's share of our liabilities for which no
partner, including the general partner, bears the economic risk of loss, known
as "nonrecourse liabilities," will be treated as a distribution of cash to that
unitholder. To the extent our distributions cause a unitholder's "at risk"
amount to be less than zero at the end of any taxable year, he must recapture
any losses deducted in previous years. See "--Limitations on Deductibility of
Losses."
A decrease in a unitholder's percentage interest in us because of our
issuance of additional common units will decrease his share of our nonrecourse
liabilities, and thus will result in a corresponding deemed distribution of
cash. A non-pro rata distribution of money or property may result in ordinary
income to a unitholder, regardless of his tax basis in his common units, if the
distribution reduces the unitholder's share of our "unrealized receivables,"
including depreciation recapture, and/or substantially appreciated "inventory
items," both as defined in Section 751 of the Internal Revenue Code, and
collectively, "Section 751 Assets." To that extent, he will be treated as
having been distributed his proportionate share of the Section 751 Assets and
having exchanged those assets with us in return for the non-pro rata portion of
the actual distribution made to him. This latter deemed exchange will generally
result in the unitholder's realization of ordinary income. That income will
equal the excess of (1) the non-pro rata portion of that distribution over (2)
the unitholder's tax basis for the share of Section 751 Assets deemed
relinquished in the exchange.
Ratio of Taxable Income to Distributions. We estimate that a purchaser of
common units in this offering who holds those common units from the date of
closing of this offering through December 31, 2002, will be allocated an amount
of federal taxable income for that period that will be less than 30% of the
cash distributed with respect to that period. We anticipate that after the
taxable year ending December 31, 2002, the ratio of taxable income allocable to
cash distributions to the unitholders will increase. These estimates are based
upon the assumption that gross income from operations will approximate the
amount required to make the minimum quarterly distribution on all units and
other assumptions with respect to capital expenditures, cash flow and
anticipated cash distributions. These estimates and assumptions are subject to,
among other things, numerous business, economic, regulatory, competitive and
political uncertainties beyond our control. Further, the estimates are based on
current tax law and tax reporting positions that we have adopted and with which
the IRS could disagree. Accordingly, we cannot assure you that these estimates
will prove to be correct. The actual percentage of distributions that will
constitute taxable income could be higher or lower, and any differences could
be material and could materially affect the value of the common units.
Basis of Common Units. A unitholder's initial tax basis for his common units
will be the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his share of our
income and by any increases in his share of our nonrecourse liabilities. That
basis will be decreased, but not below zero, by distributions from us, by the
unitholder's share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures that are not
deductible in computing taxable income and are not required to be capitalized.
A limited partner will have no share of our debt which is recourse to the
general partner, but will have a share, generally based on his share of
profits, of our nonrecourse liabilities. See "--Disposition of Common Units--
Recognition of Gain or Loss."
Limitations on Deductibility of Losses. The deduction by a unitholder of his
share of our losses will be limited to the tax basis in his units and, in the
case of an individual unitholder or a corporate unitholder, if
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more than 50% of the value of its stock is owned directly or indirectly by five
or fewer individuals or some tax-exempt organizations, to the amount for which
the unitholder is considered to be "at risk" with respect to our activities, if
that is less than his tax basis. A unitholder must recapture losses deducted in
previous years to the extent that distributions cause his at risk amount to be
less than zero at the end of any taxable year. Losses disallowed to a
unitholder or recaptured as a result of these limitations will carry forward
and will be allowable to the extent that his tax basis or at risk amount,
whichever is the limiting factor, is subsequently increased. Upon the taxable
disposition of a unit, any gain recognized by a unitholder can be offset by
losses that were previously suspended by the at risk limitation but may not be
offset by losses suspended by the basis limitation. Any excess loss above that
gain previously suspended by the at risk or basis limitations is no longer
utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of
his units, excluding any portion of that basis attributable to his share of our
nonrecourse liabilities, reduced by any amount of money he borrows to acquire
or hold his units, if the lender of those borrowed funds owns an interest in
us, is related to the unitholder or can look only to the units for repayment. A
unitholder's at risk amount will increase or decrease as the tax basis of the
unitholder's units increases or decreases, other than tax basis increases or
decreases attributable to increases or decreases in his share of our
nonrecourse liabilities.
The passive loss limitations generally provide that individuals, estates,
trusts and some closely-held corporations and personal service corporations can
deduct losses from passive activities, which are generally activities in which
the taxpayer does not materially participate, only to the extent of the
taxpayer's income from those passive activities. The passive loss limitations
are applied separately with respect to each publicly-traded partnership.
Consequently, any passive losses we generate will only be available to offset
our passive income generated in the future and will not be available to offset
income from other passive activities or investments, including other publicly-
traded partnerships, or salary or active business income. Passive losses that
are not deductible because they exceed a unitholder's income generated by us
may be deducted in full when he disposes of his entire investment in us in a
fully taxable transaction with an unrelated party. The passive activity loss
rules are applied after other applicable limitations on deductions, including
the at risk rules and the basis limitation.
A unitholder's share of our net income may be offset by any suspended
passive losses, but it may not be offset by any other current or carryover
losses from other passive activities, including those attributable to other
publicly-traded partnerships. The IRS has announced that Treasury Regulations
will be issued that characterize net passive income from a publicly-traded
partnership as investment income for purposes of the limitations on the
deductibility of investment interest.
Limitations on Interest Deductions. The deductibility of a non-corporate
taxpayer's "investment interest expense" is generally limited to the amount of
that taxpayer's "net investment income." As noted, a unitholder's share of our
net passive income will be treated as investment income for this purpose. In
addition, the unitholder's share of our portfolio income will be treated as
investment income. Investment interest expense includes:
. interest on indebtedness properly allocable to property held for
investment;
. our interest expense attributed to portfolio income; and
. the portion of interest expense incurred to purchase or carry an interest
in a passive activity to the extent attributable to portfolio income.
The computation of a unitholder's investment interest expense will take into
account interest on any margin account borrowing or other loan incurred to
purchase or carry a unit. Net investment income includes gross income from
property held for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than interest, directly
connected with the production of investment income, but generally does not
include gains attributable to the disposition of property held for investment.
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Entity-Level Collections. If we are required or elect under applicable law
to pay any federal, state or local income tax on behalf of any unitholder or
the general partner or any former unitholder, we are authorized to pay those
taxes from our funds. That payment, if made, will be treated as a distribution
of cash to the partner on whose behalf the payment was made. If the payment is
made on behalf of a person whose identity cannot be determined, we are
authorized to treat the payment as a distribution to all current unitholders.
We are authorized to amend the partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units and to adjust
later distributions, so that after giving effect to these distributions, the
priority and characterization of distributions otherwise applicable under the
partnership agreement is maintained as nearly as is practicable. Payments by us
as described above could give rise to an overpayment of tax on behalf of an
individual partner in which event the partner could file a claim for credit or
refund.
Allocation of Income, Gain, Loss and Deduction. In general, if we have a net
profit, our items of income, gain, loss and deduction will be allocated among
the general partner and the unitholders in accordance with their particular
percentage interests in us. At any time that distributions are made to the
common units and not to the subordinated units, or that incentive distributions
are made to the general partner, gross income will be allocated to the
recipients to the extent of these distributions. If we have a net loss for the
entire year, the amount of that loss will be allocated first, to the general
partner and the unitholders in accordance with their particular percentage
interests in us to the extent of their positive capital accounts and, second,
to the general partner.
Specified items of our income, gain, loss and deduction will be allocated to
account for the difference between the tax basis and fair market value of
property contributed to us by the general partner, referred to in this
discussion as "Contributed Property," and to account for the difference between
the fair market value of our assets and their carrying value on our books at
the time of the offering. The effect of these allocations to a unitholder
purchasing common units in this offering will be essentially the same as if the
tax basis of our assets were equal to their fair market value at the time of
this offering. In addition, specified items of recapture income will be
allocated to the extent possible to the partner who was allocated the deduction
giving rise to the treatment of that gain as recapture income in order to
minimize the recognition of ordinary income by some unitholders. Finally,
although we do not expect that our operations will result in the creation of
negative capital accounts, if negative capital accounts nevertheless result,
items of our income and gain will be allocated in an amount and manner
sufficient to eliminate the negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction, other than an
allocation required by the Internal Revenue Code to eliminate the difference
between a partner's "book" capital account, credited with the fair market value
of Contributed Property, and "tax" capital account, credited with the tax basis
of Contributed Property (the "Book-Tax Disparity"), will generally be given
effect for federal income tax purposes in determining a partner's distributive
share of an item of income, gain, loss or deduction only if the allocation has
substantial economic effect. In any other case, a partner's distributive share
of an item will be determined on the basis of the partner's interest in us,
which will be determined by taking into account all the facts and
circumstances, including the partner's relative contributions to us, the
interests of the partners in economic profits and losses, the interest of the
partners in cash flow and other nonliquidating distributions and rights of the
partners to distributions of capital upon liquidation.
Counsel is of the opinion that, with the exception of the issues described
in "--Tax Consequences of Unit Ownership--Section 754 Election" and "--
Disposition of Common Units--Allocations Between Transferors and Transferees,"
allocations under our partnership agreement will be given effect for federal
income tax purposes in determining a partner's distributive share of an item of
income, gain, loss or deduction.
Treatment of Short Sales. A unitholder whose units are loaned to a "short
seller" to cover a short sale of units may be considered as having disposed of
ownership of those units. If so, he would no longer be a partner for those
units during the period of the loan and may recognize gain or loss from the
disposition. As a result, during this period:
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. any of our income, gain, loss or deduction with respect to those units
would not be reportable by the unitholder;
. any cash distributions received by the unitholder for those units would
be fully taxable; and
. all of these distributions would appear to be treated as ordinary income.
Unitholders desiring to assure their status as partners and avoid the risk
of gain recognition should modify any applicable brokerage account agreements
to prohibit their brokers from borrowing their units. The IRS has announced
that it is actively studying issues relating to the tax treatment of short
sales of partnership interests. See also "--Disposition of Common Units--
Recognition of Gain or Loss."
Alternative Minimum Tax. Although it is not expected that we will generate
significant tax preference items or adjustments, each unitholder will be
required to take into account his distributive share of any items of our
income, gain, loss or deduction for purposes of the alternative minimum tax.
The minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of
alternative minimum taxable income in excess of the exemption amount and 28% on
any additional alternative minimum taxable income. Prospective unitholders
should consult with their tax advisors as to the impact of an investment in
units on their liability for the alternative minimum tax.
Tax Rates. In general the highest effective United States federal income tax
rate for individuals for 1999 is 39.6% and the maximum United States federal
income tax rate for net capital gains of an individual for 1999 is 20% if the
asset disposed of was held for more than 12 months at the time of disposition.
Section 754 Election. We have made the election permitted by Section 754 of
the Internal Revenue Code. That election is irrevocable without the consent of
the IRS. The election will generally permit us to adjust a common unit
purchaser's tax basis in our assets ("inside basis") under Section 743(b) of
the Internal Revenue Code to reflect his purchase price. This election does not
apply to a person who purchases common units directly from us. The Section
743(b) adjustment belongs to the purchaser and not to other partners. For
purposes of this discussion, a partner's inside basis in our assets will be
considered to have two components: (1) his share of our tax basis in our assets
("common basis") and (2) his Section 743(b) adjustment to that basis.
Proposed Treasury regulations under Section 743 of the Internal Revenue Code
require, if the remedial allocation method is adopted (which we have), a
portion of the Section 743(b) adjustment attributable to recovery property to
be depreciated over the remaining cost recovery period for the Section 704(c)
built-in gain. Nevertheless, the proposed regulations under Section 197
indicate that the Section 743(b) adjustment attributable to an amortizable
Section 197 intangible should be treated as a newly-acquired asset placed in
service in the month when the purchaser acquires the unit. Under Treasury
Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable
to property subject to depreciation under Section 167 of the Internal Revenue
Code rather than cost recovery deductions under Section 168 is generally
required to be depreciated using either the straight-line method or the 150%
declining balance method. Although the proposed regulations under Section 743
will likely eliminate many of the problems if finalized in their current form,
the depreciation and amortization methods and useful lives associated with the
Section 743(b) adjustment may differ from the methods and useful lives
generally used to depreciate the common basis in these properties. Under our
partnership agreement, the general partner is authorized to adopt a convention
to preserve the uniformity of units even if that convention is not consistent
with specified Treasury Regulations. See "--Tax Treatment of Operations--
Uniformity of Units."
Although counsel is unable to opine as to the validity of this approach, we
intend to depreciate the portion of a Section 743(b) adjustment attributable to
unrealized appreciation in the value of Contributed Property or Adjusted
Property, to the extent of any unamortized Book-Tax Disparity, using a rate of
depreciation or amortization derived from the depreciation or amortization
method and useful life applied to the common basis of the property, or treat
that portion as non-amortizable to the extent attributable to property the
common basis
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of which is not amortizable. This method is consistent with the proposed
regulations under Section 743 but is arguably inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6) and Proposed Treasury Regulation
Section 1.197-2(g)(3), neither of which is expected to directly apply to a
material portion of our assets. To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Treasury Regulations and
legislative history. If we determine that this position cannot reasonably be
taken, we may adopt a depreciation or amortization convention under which all
purchasers acquiring units in the same month would receive depreciation or
amortization, whether attributable to common basis or Section 743(b)
adjustment, based upon the same applicable rate as if they had purchased a
direct interest in our assets. This kind of aggregate approach may result in
lower annual depreciation or amortization deductions than would otherwise be
allowable to some unitholders. See "--Tax Treatment of Operations--Uniformity
of Units."
The allocation of the Section 743(b) adjustment among our assets must be
made in accordance with the Internal Revenue Code. The IRS could seek to
reallocate some or all of any Section 743(b) adjustment to goodwill not so
allocated by us. Goodwill, as an intangible asset, is generally amortizable
over a longer period of time or under a less accelerated method than our
tangible assets.
A Section 754 election is advantageous if the transferee's tax basis in his
units is higher than the units' share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of the election,
the transferee would have a higher tax basis in his share of our assets for
purposes of calculating, among other items, his depreciation and depletion
deductions and his share of any gain or loss on a sale of our assets.
Conversely, a Section 754 election is disadvantageous if the transferee's tax
basis in his units is lower than those units' share of the aggregate tax basis
of our assets immediately prior to the transfer. Thus, the fair market value of
the units may be affected either favorably or adversely by the election.
The calculations involved in the Section 754 election are complex and will
be made on the basis of assumptions as to the value of our assets and other
matters. We cannot assure you that the determinations made by us will not be
successfully challenged by the IRS and that the deductions resulting from them
will not be reduced or disallowed altogether. Should the IRS require a
different basis adjustment to be made, and should, in our opinion, the expense
of compliance exceed the benefit of the election, we may seek permission from
the IRS to revoke our Section 754 election. If permission is granted, a
subsequent purchaser of units may be allocated more income than he would have
been allocated had the election not been revoked.
Tax Treatment of Operations
Accounting Method and Taxable Year. We use the year ending December 31 as
our taxable year and the accrual method of accounting for federal income tax
purposes. Each unitholder will be required to include in income his allocable
share of our income, gain, loss and deduction for our taxable year ending
within or with his taxable year. In addition, a unitholder who has a taxable
year ending on a date other than December 31 and who disposes of all of his
units following the close of our taxable year but before the close of his
taxable year must include his allocable share of our income, gain, loss and
deduction in income for his taxable year, with the result that he will be
required to include in income for his taxable year his share of more than one
year of our income, gain, loss and deduction. See "--Disposition of Common
Units--Allocations Between Transferors and Transferees."
Initial Tax Basis, Depreciation and Amortization. The tax basis established
for our assets will be used for purposes of computing depreciation and cost
recovery deductions and, ultimately, gain or loss on the disposition of these
assets. The federal income tax burden associated with the difference between
the fair market value of our property and its tax basis immediately prior to
this offering will be borne by partners holding interests in us prior to this
offering. See "--Allocation of Income, Gain, Loss and Deduction."
To the extent allowable, we may elect to use the depreciation and cost
recovery methods that will result in the largest deductions being taken in the
early years after assets are placed in service. We are not entitled to
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any amortization deductions with respect to any goodwill conveyed to us on
formation. Property we subsequently acquire or construct may be depreciated
using accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure, or otherwise,
all or a portion of any gain, determined by reference to the amount of
depreciation previously deducted and the nature of the property, may be subject
to the recapture rules and taxed as ordinary income rather than capital gain.
Similarly, a partner who has taken cost recovery or depreciation deductions
with respect to property we own may be required to recapture those deductions
as ordinary income upon a sale of his interest in us. See "--Tax Consequences
of Unit Ownership--Allocation of Income, Gain, Loss and Deduction" and "--
Disposition of Common Units-- Recognition of Gain or Loss."
The costs incurred in promoting the issuance of units (i.e. syndication
expenses) must be capitalized and cannot be deducted currently, ratably or upon
our termination. There are uncertainties regarding the classification of costs
as organization expenses, which may be amortized, and as syndication expenses,
which may not be amortized. Under recently adopted regulations, the
underwriting discounts and commissions would be treated as a syndication cost.
Valuation and Tax Basis of Our Properties. The federal income tax
consequences of the ownership and disposition of units will depend in part on
our estimates of the relative fair market values, and determinations of the
initial tax bases, of our assets. Although we may from time to time consult
with professional appraisers regarding valuation matters, we will make many of
the relative fair market value estimates ourselves. These estimates and
determinations of basis are subject to challenge and will not be binding on the
IRS or the courts. If the estimates of fair market value or determinations of
basis are later found to be incorrect, the character and amount of items of
income, gain, loss or deductions previously reported by unitholders might
change, and unitholders might be required to adjust their tax liability for
prior years.
Disposition of Common Units
Recognition of Gain or Loss. Gain or loss will be recognized on a sale of
units equal to the difference between the amount realized and the unitholder's
tax basis for the units sold. A unitholder's amount realized will be measured
by the sum of the cash or the fair market value of other property received plus
his share of our nonrecourse liabilities. Because the amount realized includes
a unitholder's share of our nonrecourse liabilities, the gain recognized on the
sale of units could result in a tax liability in excess of any cash received
from the sale.
Prior distributions from us in excess of cumulative net taxable income for a
common unit that decreased a unitholder's tax basis in that common unit will,
in effect, become taxable income if the common unit is sold at a price greater
than the unitholder's tax basis in that common unit, even if the price is less
than his original cost.
Should the IRS successfully contest our convention to amortize only a
portion of the Section 743(b) adjustment, described under "--Tax Consequences
of Unit Ownership--Section 754 Election," attributable to an amortizable
Section 197 intangible after a sale by the general partner of units, a
unitholder could realize additional gain from the sale of units than had our
convention been respected. In that case, the unitholder may have been entitled
to additional deductions against income in prior years but may be unable to
claim them, with the result to him of greater overall taxable income than
appropriate. Counsel is unable to opine as to the validity of the convention
but believes a contest by the IRS is unlikely because a successful contest
could result in substantial additional deductions to other unitholders.
Except as noted below, gain or loss recognized by a unitholder, other than a
"dealer" in units, on the sale or exchange of a unit held for more than one
year will generally be taxable as capital gain or loss. Capital gain recognized
by an individual on the sale of units held more than 12 months will generally
be taxed a maximum
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rate of 20%. A portion of this gain or loss, which will likely be substantial,
however, will be separately computed and taxed as ordinary income or loss under
Section 751 of the Internal Revenue Code to the extent attributable to assets
giving rise to depreciation recapture or other "unrealized receivables" or to
"inventory items" we own. The term "unrealized receivables" includes potential
recapture items, including depreciation recapture. Ordinary income attributable
to unrealized receivables, inventory items and depreciation recapture may
exceed net taxable gain realized upon the sale of the unit and may be
recognized even if there is a net taxable loss realized on the sale of the
unit. Thus, a unitholder may recognize both ordinary income and a capital loss
upon a disposition of units. Net capital loss may offset no more than $3,000 of
ordinary income in the case of individuals and may only be used to offset
capital gain in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in
separate transactions must combine those interests and maintain a single
adjusted tax basis. Upon a sale or other disposition of less than all of those
interests, a portion of that tax basis must be allocated to the interests sold
using an "equitable apportionment" method. The ruling is unclear as to how the
holding period of these interests is determined once they are combined. If this
ruling is applicable to the holders of common units, a common unitholder will
be unable to select high or low basis common units to sell as would be the case
with corporate stock. It is not clear whether the ruling applies to us,
because, similar to corporate stock, interests in us are evidenced by separate
certificates. Accordingly, counsel is unable to opine as to the effect this
ruling will have on the unitholders. A unitholder considering the purchase of
additional units or a sale of common units purchased in separate transactions
should consult his tax advisor as to the possible consequences of this ruling.
Specific provisions of the Internal Revenue Code affect the taxation of some
financial products and securities, including partnership interests, by treating
a taxpayer as having sold an "appreciated" partnership interest, one in which
gain would be recognized if it were sold, assigned or terminated at its fair
market value, if the taxpayer or related persons enter(s) into:
. a short sale;
. an offsetting notional principal contract; or
. a futures or forward contract with respect to the partnership interest or
substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an
offsetting notional principal contract or a futures or forward contract with
respect to the partnership interest, the taxpayer will be treated as having
sold that position if the taxpayer or a related person then acquires the
partnership interest or substantially identical property. The Secretary of
Treasury is also authorized to issue regulations that treat a taxpayer that
enters into transactions or positions that have substantially the same effect
as the preceding transactions as having constructively sold the financial
position.
Allocations Between Transferors and Transferees. In general, our taxable
income and losses will be determined annually, will be prorated on a monthly
basis and will be subsequently apportioned among the unitholders in proportion
to the number of units owned by each of them as of the opening of the NYSE on
the first business day of the month (the "Allocation Date"). However, gain or
loss realized on a sale or other disposition of our assets other than in the
ordinary course of business will be allocated among the unitholders on the
Allocation Date in the month in which that gain or loss is recognized. As a
result, a unitholder transferring units in the open market may be allocated
income, gain, loss and deduction accrued after the date of transfer.
The use of this method may not be permitted under existing Treasury
Regulations. Accordingly, counsel is unable to opine on the validity of this
method of allocating income and deductions between the transferors and the
transferees of units. If this method is not allowed under the Treasury
Regulations, or only applies to transfers of less than all of the unitholder's
interest, our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of allocation between
transferors and transferees, as
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well as among partners whose interests otherwise vary during a taxable period,
to conform to a method permitted under future Treasury Regulations.
A unitholder who owns units at any time during a quarter and who disposes of
these units prior to the record date set for a cash distribution for that
quarter will be allocated items of our income, gain, loss and deductions
attributable to that quarter but will not be entitled to receive that cash
distribution.
Notification Requirements. A unitholder who sells or exchanges units is
required to notify us in writing of that sale or exchange within 30 days after
the sale or exchange and in any event by no later than January 15 of the year
following the calendar year in which the sale or exchange occurred. We are
required to notify the IRS of that transaction and to furnish specified
information to the transferor and transferee. However, these reporting
requirements do not apply to a sale by an individual who is a citizen of the
United States and who effects the sale or exchange through a broker.
Additionally, a transferor and a transferee of a unit will be required to
furnish statements to the IRS, filed with their income tax returns for the
taxable year in which the sale or exchange occurred, that describe the amount
of the consideration received for the unit that is allocated to our goodwill or
going concern value. Failure to satisfy these reporting obligations may lead to
the imposition of substantial penalties.
Constructive Termination. We will be considered to have been terminated for
tax purposes if there is a sale or exchange of 50% or more of the total
interests in our capital and profits within a 12-month period. A constructive
termination results in the closing of our taxable year for all unitholders. In
the case of a unitholder reporting on a taxable year other than a fiscal year
ending December 31, the closing of our taxable year may result in more than 12
months of our taxable income or loss being includable in his taxable income for
the year of termination. New tax elections required to be made by us, including
a new election under Section 754 of the Internal Revenue Code, must be made
after a termination, and a termination would result in a deferral of our
deductions for depreciation. A termination could also result in penalties if we
were unable to determine that the termination had occurred. Moreover, a
termination might either accelerate the application of, or subject us to, any
tax legislation enacted before the termination.
Uniformity of Units
Because we cannot match transferors and transferees of units, we must
maintain uniformity of the economic and tax characteristics of the units to a
purchaser of these units. In the absence of uniformity, compliance with a
number of federal income tax requirements, both statutory and regulatory, could
be substantially diminished. A lack of uniformity can result from a literal
application of Treasury Regulation Section 1.167(c)-1(a)(6) and Proposed
Treasury Regulation Section 1.197-2(g)(3). Any non-uniformity could have a
negative impact on the value of the units. See "--Tax Consequences of Unit
Ownership--Section 754 Election."
We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of contributed property or
adjusted property, to the extent of any unamortized Book-Tax Disparity, using a
rate of depreciation or amortization derived from the depreciation or
amortization method and useful life applied to the common basis of that
property, or treat that portion as nonamortizable, to the extent attributable
to property the common basis of which is not amortizable, consistent with the
proposed regulations under Section 743, but despite its inconsistency with
Treasury Regulation Section 1.167(c)-1(a)(6) and Proposed Treasury Regulation
Section 1.197-2(g)(3), neither of which is expected to directly apply to a
material portion of our assets. See "--Tax Consequences of Unit Ownership--
Section 754 Election." To the extent that the Section 743 (b) adjustment is
attributable to appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Treasury Regulations and
legislative history. If we determine that this type of position cannot
reasonably be taken, we may adopt a depreciation and amortization convention
under which all purchasers acquiring units in the same month would receive
depreciation and amortization deductions, whether attributable to a common
basis or Section 743(b) adjustment, based upon the same applicable rate as if
they had purchased a direct interest in our property. If this kind of an
aggregate
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approach is adopted, it may result in lower annual depreciation and
amortization deductions than would otherwise be allowable to some unitholders
and risk the loss of depreciation and amortization deductions not taken in the
year that these deductions are otherwise allowable. This convention will not be
adopted if we determine that the loss of depreciation and amortization
deductions will have a material adverse effect on the unitholders. If we choose
not to utilize this aggregate method, we may use any other reasonable
depreciation and amortization convention to preserve the uniformity of the
intrinsic tax characteristics of any units that would not have a material
adverse effect on the unitholders. The IRS may challenge any method of
depreciating the Section 743(b) adjustment described in this paragraph. If this
type of challenge were sustained, the uniformity of units might be affected,
and the gain from the sale of units might be increased without the benefit of
additional deductions. See "--Disposition of Common Units--Recognition of Gain
or Loss."
Tax-Exempt Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations, other foreign persons
and regulated investment companies raises issues unique to those investors and,
as described below, may have substantially adverse tax consequences. Employee
benefit plans and most other organizations exempt from federal income tax,
including individual retirement accounts and other retirement plans, are
subject to federal income tax on unrelated business taxable income. Virtually
all of our income allocated to a unitholder which is a tax-exempt organization
will be unrelated business taxable income and will be taxable to the
unitholder.
A regulated investment company or "mutual fund" is required to derive 90% or
more of its gross income from interest, dividends and gains from the sale of
stocks or securities or foreign currency or specified related sources. It is
not anticipated that any significant amount of our gross income will include
that type of income.
Non-resident aliens and foreign corporations, trusts or estates that own
units will be considered to be engaged in business in the United States on
account of ownership of units. As a consequence they will be required to file
federal tax returns for their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on any net income or gain. Generally, a
partnership is required to pay a withholding tax on the portion of the
partnership's income that is effectively connected with the conduct of a United
States trade or business and which is allocable to the foreign partners,
regardless of whether any actual distributions have been made to these
partners. However, under rules applicable to publicly traded partnerships, we
will withhold (currently at the rate of 39.6%) on actual cash distributions
made quarterly to foreign unitholders. Each foreign unitholder must obtain a
taxpayer identification number from the IRS and submit that number to our
transfer agent on a Form W-8 in order to obtain credit for the taxes withheld.
A change in applicable law may require us to change these procedures.
Because a foreign corporation that owns units will be treated as engaged in
a United States trade or business, that a corporation may be subject to United
States branch profits tax at a rate of 30%, in addition to regular federal
income tax, on its share of our income and gain, as adjusted for changes in the
foreign corporation's "U.S. net equity," which are effectively connected with
the conduct of a United States trade or business. That tax may be reduced or
eliminated by an income tax treaty between the United States and the country in
which the foreign corporate unitholder is a "qualified resident." In addition,
this type of unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue Code.
Under a ruling of the IRS, a foreign unitholder who sells or otherwise
disposes of a unit will be subject to federal income tax on gain realized on
the disposition of that unit to the extent that this gain is effectively
connected with a United States trade or business of the foreign unitholder.
Apart from the ruling, a foreign unitholder will not be taxed or subject to
withholding upon the disposition of a unit if he has owned less than 5% in
value of the units during the five-year period ending on the date of the
disposition and if the units are regularly traded on an established securities
market at the time of the disposition.
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Administrative Matters
Information Returns and Audit Procedures. We intend to furnish to each
unitholder, within 90 days after the close of each calendar year, specific tax
information, including a Schedule K-1, which describes each unitholder's share
of our income, gain, loss and deduction for our preceding taxable year. In
preparing this information, which will generally not be reviewed by counsel,
we will use various accounting and reporting conventions, some of which have
been mentioned earlier, to determine the unitholder's share of income, gain,
loss and deduction. We cannot assure you that any of those conventions will
yield a result that conforms to the requirements of the Internal Revenue Code,
regulations or administrative interpretations of the IRS. Neither we nor
counsel can assure prospective unitholders that the IRS will not successfully
contend in court that those accounting and reporting conventions are
impermissible. Any challenge by the IRS could negatively affect the value of
the units.
The IRS may audit our federal income tax information returns. Adjustments
resulting from any audit of this kind may require each unitholder to adjust a
prior year's tax liability, and possibly may result in an audit of that
unitholder's own return. Any audit of a unitholder's return could result in
adjustments not related to our returns as well as those related to our
returns.
Partnerships generally are treated as separate entities for purposes of
federal tax audits, judicial review of administrative adjustments by the IRS
and tax settlement proceedings. The tax treatment of partnership items of
income, gain, loss and deduction are determined in a partnership proceeding
rather than in separate proceedings with the partners. The Internal Revenue
Code provides for one partner to be designated as the "Tax Matters Partner"
for these purposes. The partnership agreement appoints the general partner as
our Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters Partner can extend
the statute of limitations for assessment of tax deficiencies against
unitholders for items in our returns. The Tax Matters Partner may bind a
unitholder with less than a 1% profits interest in us to a settlement with the
IRS unless that unitholder elects, by filing a statement with the IRS, not to
give that authority to the Tax Matters Partner. The Tax Matters Partner may
seek judicial review, by which all the unitholders are bound, of a final
partnership administrative adjustment and, if the Tax Matters Partner fails to
seek judicial review, judicial review may be sought by any unitholder having
at least a 1% interest in profits or by any group of unitholders having in the
aggregate at least a 5% interest in profits. However, only one action for
judicial review will go forward, and each unitholder with an interest in the
outcome may participate. However, if we elect to be treated as a large
partnership, a unitholder will not have the right to participate in settlement
conferences with the IRS or to seek a refund.
A unitholder must file a statement with the IRS identifying the treatment
of any item on his federal income tax return that is not consistent with the
treatment of the item on our return. Intentional or negligent disregard of the
consistency requirement may subject a unitholder to substantial penalties.
However, if we elect to be treated as a large partnership, the unitholders
would be required to treat all partnership items in a manner consistent with
our return.
Nominee Reporting. Persons who hold an interest in us as a nominee for
another person are required to furnish to us:
(a) the name, address and taxpayer identification number of the
beneficial owner and the nominee;
(b) whether the beneficial owner is
(1) a person that is not a United States person,
(2) a foreign government, an international organization or any wholly
owned agency or instrumentality of either of the foregoing, or
(3) a tax-exempt entity;
121
<PAGE>
(c) the amount and description of units held, acquired or transferred
for the beneficial owner; and
(d) specific information including the dates of acquisitions and
transfers, means of acquisitions and transfers, and acquisition cost for
purchases, as well as the amount of net proceeds from sales.
Brokers and financial institutions are required to furnish additional
information, including whether they are United States persons and specific
information on units they acquire, hold or transfer for their own account. A
penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is
imposed by the Internal Revenue Code for failure to report that information to
us. The nominee is required to supply the beneficial owner of the units with
the information furnished to us.
Registration as a Tax Shelter. The Internal Revenue Code requires that "tax
shelters" be registered with the Secretary of the Treasury. The temporary
Treasury Regulations interpreting the tax shelter registration provisions of
the Internal Revenue Code are extremely broad. It is arguable that we are not
subject to the registration requirement on the basis that we will not
constitute a tax shelter. However, we have registered as a tax shelter with
the Secretary of Treasury in the absence of assurance that we will not be
subject to tax shelter registration and in light of the substantial penalties
which might be imposed if registration is required and not undertaken.
Issuance of this registration number does not indicate that investment in
us or the claimed tax benefits have been reviewed, examined or approved by the
IRS.
Our tax shelter registration number is 99061000009. A unitholder who sells
or otherwise transfers a unit in a later transaction must furnish the
registration number to the transferee. The penalty for failure of the
transferor of a unit to furnish the registration number to the transferee is
$100 for each failure. The unitholders must disclose our tax shelter
registration number on Form 8271 to be attached to the tax return on which any
deduction, loss or other benefit generated by us is claimed or on which any of
our income is included. A unitholder who fails to disclose the tax shelter
registration number on his return, without reasonable cause for that failure,
will be subject to a $250 penalty for each failure. Any penalties discussed
are not deductible for federal income tax purposes.
Accuracy-related Penalties. An additional tax equal to 20% of the amount of
any portion of an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or regulations,
substantial understatements of income tax and substantial valuation
misstatements, is imposed by the Internal Revenue Code. No penalty will be
imposed, however, for any portion of an underpayment if it is shown that there
was a reasonable cause for that portion and that the taxpayer acted in good
faith regarding that portion.
A substantial understatement of income tax in any taxable year exists if
the amount of the understatement exceeds the greater of 10% of the tax
required to be shown on the return for the taxable year or $5,000 ($10,000 for
most corporations). The amount of any understatement subject to penalty
generally is reduced if any portion is attributable to a position adopted on
the return:
(1) for which there is, or was, "substantial authority," or
(2) as to which there is a reasonable basis and the pertinent facts of
that position are disclosed on the return.
More stringent rules apply to "tax shelters," a term that in this context
does not appear to include us. If any item of income, gain, loss or deduction
included in the distributive shares of unitholders might result in that kind
of an "understatement" of income for which no "substantial authority" exists,
we must disclose the pertinent facts on our return. In addition, we will make
a reasonable effort to furnish sufficient information for unitholders to make
adequate disclosure on their returns to avoid liability for this penalty.
122
<PAGE>
A substantial valuation misstatement exists if the value of any property, or
the adjusted basis of any property, claimed on a tax return is 200% or more of
the amount determined to be the correct amount of the valuation or adjusted
basis. No penalty is imposed unless the portion of the underpayment
attributable to a substantial valuation misstatement exceeds $5,000 ($10,000
for most corporations). If the valuation claimed on a return is 400% or more
than the correct valuation, the penalty imposed increases to 40%.
State, Local and Other Tax Considerations
In addition to federal income taxes, you will be subject to other taxes,
including state and local income taxes, unincorporated business taxes, and
estate, inheritance or intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property. Although an analysis of
those various taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. We own property or do
business in Alabama, Arizona, Arkansas, California, Colorado, Florida,
Illinois, Indiana, Kansas, Kentucky, Louisiana, Minnesota, Mississippi,
Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota,
Texas, Utah and Wyoming. Of these states, Florida, South Dakota, Texas, and
Wyoming do not currently impose a personal income tax. A unitholder will be
required to file state income tax returns and to pay state income taxes in some
or all of these states in which we do business or own property and may be
subject to penalties for failure to comply with those requirements. In some
states, tax losses may not produce a tax benefit in the year incurred and also
may not be available to offset income in subsequent taxable years. Some of the
states may require us, or we may elect, to withhold a percentage of income from
amounts to be distributed to a unitholder who is not a resident of the state.
Withholding, the amount of which may be greater or less than a particular
unitholder's income tax liability to the state, generally does not relieve a
nonresident unitholder from the obligation to file an income tax return.
Amounts withheld may be treated as if distributed to unitholders for purposes
of determining the amounts distributed by us. See "--Tax Consequences of Unit
Ownership--Entity-Level Collections." Based on current law and our estimate of
our future operations, the general partner anticipates that any amounts
required to be withheld will not be material. We may also own property or do
business in other states in the future.
It is the responsibility of each unitholder to investigate the legal and tax
consequences, under the laws of pertinent states and localities, of his
investment in us. Accordingly, each prospective unitholder should consult, and
must depend upon, his own tax counsel or other advisor with regard to those
matters. Further, it is the responsibility of each unitholder to file all state
and local, as well as United States federal tax returns that may be required of
him. Counsel has not rendered an opinion on the state or local tax consequences
of an investment in us.
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<PAGE>
INVESTMENT IN PLAINS ALL AMERICAN PIPELINE BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to additional
considerations because the investments of these plans are subject to the
fiduciary responsibility and prohibited transaction provisions of ERISA, and
restrictions imposed by Section 4975 of the Internal Revenue Code. For these
purposes the term "employee benefit plan" includes, but is not limited to,
qualified pension, profit-sharing and stock bonus plans, Keogh plans,
simplified employee pension plans and tax deferred annuities or IRAs
established or maintained by an employer or employee organization. Among other
things, consideration should be given to:
(a) whether the investment is prudent under Section 404(a) (1) (B) of
ERISA;
(b) whether in making the investment, that plan will satisfy the
diversification requirements of Section 404(a) (1) (C) of ERISA; and
(c) whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential after-tax
investment return.
The person with investment discretion with respect to the assets of an
employee benefit plan, often called a fiduciary, should determine whether an
investment in us is authorized by the appropriate governing instrument and is a
proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibits
employee benefit plans, and also IRAs that are not considered part of an
employee benefit plan, from engaging in specified transactions involving "plan
assets" with parties that are "parties in interest" under ERISA or
"disqualified persons" under the Internal Revenue Code with respect to the
plan.
In addition to considering whether the purchase of common units is a
prohibited transaction, a fiduciary of an employee benefit plan should consider
whether the plan will, by investing in us, be deemed to own an undivided
interest in our assets, with the result that the general partner also would be
fiduciaries of the plan and our operations would be subject to the regulatory
restrictions of ERISA, including its prohibited transaction rules, as well as
the prohibited transaction rules of the Internal Revenue Code.
The Department of Labor regulations provide guidance with respect to whether
the assets of an entity in which employee benefit plans acquire equity
interests would be deemed "plan assets" under some circumstances. Under these
regulations, an entity's assets would not be considered to be "plan assets" if,
among other things,
(a) the equity interests acquired by employee benefit plans are
publicly offered securities; i.e., the equity interests are widely held by
100 or more investors independent of the issuer and each other, freely
transferable and registered under some provisions of the federal securities
laws,
(b) the entity is an "operating company," - i.e., it is primarily
engaged in the production or sale of a product or service other than the
investment of capital either directly or through a majority owned
subsidiary or subsidiaries, or
(c) there is no significant investment by benefit plan investors, which
is defined to mean that less than 25% of the value of each class of equity
interest, disregarding some interests held by the general partner, its
affiliates, and some other persons, is held by the employee benefit plans
referred to above, IRAs and other employee benefit plans not subject to
ERISA, including governmental plans.
Our assets should not be considered "plan assets" under these regulations
because it is expected that the investment will satisfy the requirements in (a)
above.
Plan fiduciaries contemplating a purchase of common units should consult
with their own counsel regarding the consequences under ERISA and the Internal
Revenue Code in light of the serious penalties imposed on persons who engage in
prohibited transactions or other violations.
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<PAGE>
UNDERWRITING
Subject to the terms and conditions stated in the underwriting agreement
dated the date hereof, each of the underwriters named below have severally
agreed to purchase, and we have agreed to sell to the underwriters, the number
of common units set forth opposite the name of the underwriters.
<TABLE>
<CAPTION>
Number of
Common
Name Units
---- ---------
<S> <C>
Salomon Smith Barney Inc...........................................
Goldman, Sachs & Co................................................
A.G. Edwards & Sons, Inc...........................................
First Union Capital Markets Corp...................................
---------
Total............................................................ 2,600,000
=========
</TABLE>
The underwriting agreement provides that the obligations of the several
underwriters to purchase the common units included in this offering are subject
to approval of legal matters by counsel and to other conditions. The
underwriters are obligated to purchase all the common units (other than those
covered by the over-allotment option described below) if they purchase any of
the common units.
The underwriters propose to offer some of the common units directly to the
public at the public offering price set forth on the cover page of this
prospectus and some of the common units to dealers at the public offering price
less a concession not in excess of $ per common unit. The underwriters may
allow, and the dealers may reallow, a concession not in excess of $ per
common unit on sales to other dealers. If all of the common units are not sold
at the initial offering price, the underwriters may change the public offering
price and the other selling terms. The underwriters have advised us that they
do not intend to confirm any sales to any accounts over which they exercise
discretionary authority.
We have granted to the underwriters an option, exercisable for 30 days from
the date of this prospectus, to purchase up to 390,000 additional common units
at the public offering price less the underwriting discount. The underwriters
may exercise this option solely for the purpose of covering over-allotments, if
any, in connection with this offering. To the extent the option is exercised,
each underwriter will be obligated, subject to conditions, to purchase a number
of additional common units approximately proportionate to the underwriter's
initial purchase commitment.
Plains All American Pipeline, Plains Resources, the general partner and the
officers and directors of the general partner have agreed that, for a period of
90 days from the date of this prospectus, they will not, without the prior
written consent of Salomon Smith Barney Inc., dispose of or hedge any of our
common units or subordinated units or any securities convertible into or
exchangeable for, or that represent a right to receive, common units or
subordinated units or any securities that are senior to or on a parity with the
common units or grant any options or warrants to purchase common units or
subordinated units, other than pursuant to our long-term incentive plan. This
restriction will not prohibit our issuance of common units in connection with
acquisitions and capital improvements which are accretive on a per unit basis
in accordance with the terms of our partnership agreement.
The common stock is listed on the NYSE under the symbol "PAA."
The following table shows the underwriting discounts and commissions to be
paid to the underwriters by us in connection with this offering. These amounts
are shown assuming both no exercise and full exercise of the underwriters'
option to purchase additional shares of common units.
<TABLE>
<CAPTION>
Paid by Us
-----------------
No Full
Exercise Exercise
-------- --------
<S> <C> <C>
Per common unit............................................ $
Total.................................................... $
</TABLE>
125
<PAGE>
In connection with the offering, Salomon Smith Barney Inc., on behalf of the
underwriters, may purchase and sell shares of common units in the open market.
These transactions may include over-allotment, syndicate covering transactions
and stabilizing transactions. Over-allotment involves syndicate sales of common
units in excess of the number of common units to be purchased by the
underwriters in the offering, which creates a syndicate short position.
Syndicate covering transactions involve purchases of the common units in the
open market after the distribution has been completed in order to cover
syndicate short positions. Stabilizing transactions consist of bids or
purchases of common units made for the purpose of preventing or retarding a
decline in the market price of the common units while the offering is in
progress.
The underwriters also may impose a penalty bid. Penalty bids permit the
underwriters to reclaim a selling concession from a syndicate member when
Salomon Smith Barney Inc., in covering syndicate short positions or making
stabilizing purchases, repurchases shares originally sold by that syndicate
member.
Any of these activities may cause the price of the common units to be higher
than the price that otherwise would exist in the open market in the absence of
these transactions. These transactions may be effected on the NYSE or otherwise
and, if commenced, may be discontinued at any time.
We estimate our expenses of this offering will be approximately $500,000,
excluding underwriting discounts.
Because the National Association for Securities Dealers, Inc. ("NASD") views
the common units offered hereby as interests in a direct participation program,
the offering is being made in compliance with Rule 2810 of the NASD's Conduct
Rules. Investor suitability with respect to the common units should be judged
similarly to the suitability with respect to other securities that are listed
for trading on a national securities exchange.
The underwriters have performed certain investment banking and advisory
services for us from time to time for which they have received customary fees
and expenses. First Union National Bank, an affiliate of First Union Capital
Markets Corp., is the syndication agent and a lender under the Plains Scurlock
credit facility and a lender under our $225 million credit facility. The
proceeds of this offering will be used to repay a portion of this indebtedness.
Salomon Smith Barney Inc., Goldman, Sachs & Co. and A.G. Edwards & Sons, Inc.
were underwriters in our initial public offering that closed on November 23,
1998. The underwriters may, from time to time, engage in transactions with and
perform services for us in the ordinary course of their business.
Plains All American Pipeline, the general partner and various subsidiaries
have agreed to indemnify the several underwriters against various liabilities,
including liabilities under the Securities Act, or to contribute to payments
the underwriters may be required to make in respect of any of those
liabilities.
126
<PAGE>
VALIDITY OF THE COMMON UNITS
The validity of the common units will be passed upon for Plains All American
Pipeline by Andrews & Kurth L.L.P., Houston, Texas. Certain legal matters in
connection with the common units offered hereby will be passed upon for the
underwriters by Baker & Botts, L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements of Plains All American Pipeline, L.P.
as of December 31, 1998 and for the period from inception (November 23, 1998)
to December 31, 1998 included in this Prospectus have been so included in
reliance on the report of PricewaterhouseCoopers LLP, independent accountants,
given on the authority of said firm as experts in auditing and accounting.
The combined financial statements of the Plains Midstream Subsidiaries as of
December 31, 1997 and for the period from January 1, 1998 to November 22, 1998
and the years ended December 31, 1997 and 1996 included in this Prospectus have
been so included in reliance on the report of PricewaterhouseCoopers LLP,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
The financial statements of the Scurlock Permian Businesses as of December
31, 1998 and for the year ended December 31, 1998 included in this Prospectus
have been so included in reliance on the report of PricewaterhouseCoopers LLP,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
The financial statements of Scurlock Permian Corporation as of December 31,
1997 and for each of the two years in the period ended December 31, 1997
included in this Prospectus have been so included in reliance on the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in auditing and accounting.
The consolidated financial statements of Wingfoot Ventures Seven, Inc. as of
December 31, 1997 and 1996 and for each of the three years in the period ended
December 31, 1997 included in this Prospectus have been so included in reliance
on the report of PricewaterhouseCoopers LLP, independent accountants, given on
the authority of said firm as experts in auditing and accounting.
The consolidated balance sheet of Plains All American Inc. as of December
31, 1998 included in this Prospectus has been so included in reliance on the
report of PricewaterhouseCoopers LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting.
With respect to the unaudited consolidated financial information of Wingfoot
Ventures Seven, Inc. as of June 30, 1998 and for the six-month periods ended
June 30, 1998 and 1997, included in this Prospectus, PricewaterhouseCoopers LLP
reported that they have applied limited procedures in accordance with
professional standards for a review of such information. However, their
separate report dated September 23, 1998 appearing herein, states that they did
not audit and they do not express an opinion on that unaudited consolidated
financial information. Accordingly, the degree of reliance on their report on
such information should be restricted in light of the limited nature of the
review procedures applied. PricewaterhouseCoopers LLP is not subject to the
liability provisions of Section 11 of the Securities Act of 1933 for their
report on the unaudited consolidated financial information because that report
is not a "report" or a "part" of the registration statement prepared or
certified by PricewaterhouseCoopers LLP within the meaning of sections 7 and 11
of the Securities Act of 1933.
127
<PAGE>
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and special reports and other information with the
Securities Exchange Commission under the Securities Exchange Act of 1934. You
can inspect and/or copy these reports and other information at offices
maintained by the SEC, including:
. the principal offices of the SEC located at Judiciary Plaza, 450 Fifth
Street, N.W., Room 1024, Washington, D.C. 20549;
. the Regional Offices of the SEC located at Northwestern Atrium Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511;
. the Regional Offices of the SEC located at 7 World Trade Center, New
York, New York 10048; and
. the SEC's website at http://www.sec.gov.
Further, our common units are listed on the New York Stock Exchange, and you
can inspect similar information at the offices of the New York Stock Exchange,
located at 20 Broad Street, New York, New York 10005.
FORWARD-LOOKING STATEMENTS
Some of the information in this prospectus may contain forward-looking
statements. These statements can be identified by the use of forward-looking
terminology including "may," "believe," "will," "expect," "anticipate,"
"estimate," "continue" or other similar words. These statements discuss future
expectations, contain projections of results of operations or of financial
condition or state other "forward-looking" information. These forward-looking
statements involve risks and uncertainties. When considering these forward-
looking statements, you should keep in mind the risk factors and other
cautionary statements in this prospectus. The risk factors and other factors
noted throughout this prospectus could cause our actual results to differ
materially from those contained in any forward-looking statement.
128
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
PLAINS ALL AMERICAN PIPELINE, L.P.
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS:
Introduction............................................................ F-3
Pro Forma Consolidated Balance Sheet as of June 30, 1999................ F-4
Pro Forma Consolidated Statement of Income for the six months ended June
30, 1999............................................................... F-5
Pro Forma Consolidated Statement of Income for the year ended December
31, 1998............................................................... F-6
Notes to Pro Forma Consolidated Financial Statements.................... F-7
PLAINS ALL AMERICAN PIPELINE, L.P.
UNAUDITED CONSOLIDATED AND COMBINED INTERIM FINANCIAL STATEMENTS:
Consolidated Balance Sheets as of December 31, 1998 and June 30, 1999... F-9
Consolidated and Combined Statements of Income for the three and six
months ended June 30, 1998 (Predecessor) and 1999...................... F-10
Consolidated and Combined Statements of Cash Flows for the six months
ended June 30, 1998 (Predecessor) and 1999............................. F-11
Notes to Consolidated and Combined Financial Statements................. F-12
PLAINS ALL AMERICAN PIPELINE, L.P.
CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS:
Report of Independent Accountants....................................... F-16
Consolidated and Combined Balance Sheets as of December 31, 1997
(Predecessor) and 1998................................................. F-17
Consolidated and Combined Statements of Income:
For the years ended December 31, 1996 and 1997 and the period January
1, 1998 to November 22, 1998 (Predecessor)........................... F-18
For the period from inception (November 23, 1998) to December 31,
1998................................................................. F-18
Consolidated and Combined Statements of Cash Flows:
For the years ended December 31, 1996 and 1997 and the period January
1, 1998 to November 22, 1998 (Predecessor)........................... F-19
For the period from inception (November 23, 1998) to December 31,
1998................................................................. F-19
Consolidated Statement of Changes in Partners' Equity for the period
from Inception (November 23, 1998) to December 31, 1998................ F-20
Notes to Consolidated and Combined Financial Statements................. F-21
SCURLOCK PERMIAN BUSINESSES
UNAUDITED INTERIM FINANCIAL STATEMENTS:
Balance Sheets as of December 31, 1998 and March 31, 1999............... F-38
Statements of Operations for the three months ended March 31, 1998 and
1999................................................................... F-39
Statements of Cash Flows for the three months ended March 31, 1998 and
1999................................................................... F-40
Notes to Interim Financial Statements................................... F-41
SCURLOCK PERMIAN BUSINESSES
FINANCIAL STATEMENTS:
Report of Independent Accountants....................................... F-43
Report of Independent Accountants....................................... F-44
Statement of Operations for the years ended December 31, 1996, 1997 and
1998................................................................... F-45
Balance Sheet as of December 31, 1997 and 1998.......................... F-46
Statement of Cash Flows for the years ended December 31, 1996, 1997 and
1998................................................................... F-47
Statement of Changes in Parent Company Investment for the years ended
December 31, 1996, 1997 and 1998....................................... F-48
Notes to Financial Statements........................................... F-49
</TABLE>
F-1
<PAGE>
INDEX TO FINANCIAL STATEMENTS--(Continued)
<TABLE>
<CAPTION>
Page
----
<S> <C>
WINGFOOT VENTURES SEVEN, INC.
UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS:
Independent Accountants' Report......................................... F-58
Consolidated Balance Sheets as of December 31, 1997 and June 30, 1998... F-59
Consolidated Statements of Income for the six months ended June 30, 1997
and 1998............................................................... F-60
Consolidated Statements of Cash Flows for the six months ended June 30,
1997 and 1998.......................................................... F-61
Notes to Consolidated Financial Statements.............................. F-62
WINGFOOT VENTURES SEVEN, INC.
CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Accountants....................................... F-63
Consolidated Balance Sheets as of December 31, 1996 and 1997............ F-64
Consolidated Statements of Operations and Accumulated Deficit for the
years ended December 31, 1995, 1996 and 1997........................... F-65
Consolidated Statements of Cash Flows for the years ended December 31,
1995, 1996 and 1997.................................................... F-66
Notes to Consolidated Financial Statements.............................. F-67
PLAINS ALL AMERICAN INC.
Report of Independent Accountants....................................... F-77
Consolidated Balance Sheet as of December 31, 1998...................... F-78
Notes to Consolidated Balance Sheet..................................... F-79
</TABLE>
F-2
<PAGE>
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
Introduction
Plains All American Pipeline, L.P. (the "Partnership" or "PAA") is a limited
partnership 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 "Predecessor"). The accompanying unaudited pro forma
consolidated financial statements are presented to give effect to the
transactions described below (the "Transactions"):
. The acquisition by the Predecessor of the All American Pipeline and the SJV
Gathering System (the "All American Acquisition") from Wingfoot Ventures
Seven, Inc., ("Wingfoot"), a wholly owned subsidiary of the Goodyear Tire
and Rubber Company ("Goodyear") for approximately $400 million in cash,
which was financed in part through a borrowing of $300 million under the
Plains Midstream Subsidiaries' bank facility, with the remainder funded by a
capital contribution from Plains Resources. The acquisition was effective
July 30, 1998 and accounted for using the purchase method of accounting.
. The completion of the initial public offering ("IPO") and the transactions
whereby the Partnership became the successor to the business of the
Predecessor effective November 23, 1998.
. The acquisition by Plains Scurlock Permian, L.P. of Scurlock Permian LLC and
certain other pipeline assets (the "Scurlock Acquisition") from Marathon
Ashland Petroleum LLC ("MAP") for approximately $141 million in cash, which
was financed in part through borrowings of $92 million and $25 million under
Plains Scurlock's credit facility and PAA's existing revolving credit
agreement, respectively, and the sale of Class B Common Units to Plains All
American Inc. ("PAAI" or the "General Partner"). The acquisition was
effective May 1, 1999 and accounted for using the purchase method of
accounting.
. The public offering ("Offering") of 2,600,000 limited partner units at a
price of $19.81 per unit expected to raise approximately $51.5 million in
gross proceeds ($48.7 million, net after $2.8 million in underwriters'
discounts and commissions and offering expenses).
. The application of the proceeds from the Offering to repay a portion of our
borrowings outstanding under Plains Scurlock's credit facility.
The unaudited pro forma consolidated balance sheet as of June 30, 1999 and
the unaudited pro forma statements of income for the six months ended June 30,
1999 and the year ended December 31, 1998 are based upon the following,
respectively:
. The historical balance sheet of PAA at June 30, 1999.
. The historical consolidated statement of income of PAA for the six months
ended June 30, 1999, which includes two months' results of operations from
the Scurlock Permian Businesses ("Scurlock"), and the historical results of
operations of Scurlock for the four months ended April 30, 1999. The
Scurlock financial statements pertain to the businesses sold to PAA by MAP
and represent a carve-out financial statement presentation of a MAP
operating unit.
. The historical consolidated statement of income of PAA (for the period from
November 23, 1998 to December 31, 1998), the historical combined statement
of income of the Predecessor (for the period from January 1, 1998 to
November 22, 1998), the historical statement of operations of Scurlock for
the year ended December 31, 1998, and the historical statement of income of
Wingfoot for the six months ended June 30, 1998. Certain reclassifications
have been made to the historical Scurlock financial statements to conform to
PAA's presentation (see pro forma note H).
The unaudited pro forma consolidated financial statements are not
necessarily indicative of the results of the future operations of PAA. The
unaudited pro forma consolidated financial statements should be read in
conjunction with the notes thereto and the historical financial statements of
PAA, Scurlock and Wingfoot appearing elsewhere in this Prospectus.
The following unaudited pro forma consolidated financial statements have
been prepared as if the Offering had taken place on June 30, 1999, in the case
of the Unaudited Pro Forma Consolidated Balance Sheet, and as if the
Transactions and the Offering had taken place on January 1, 1998, in the case
of the Unaudited Pro Forma Consolidated Statements of Income for the six months
ended June 30, 1999 and the year ended December 31, 1998.
F-3
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED BALANCE SHEET (unaudited)
June 30, 1999
(in thousands, except unit data)
<TABLE>
<CAPTION>
Historical
--------------
Plains All
American Offering Pro Forma
ASSETS Pipeline, L.P. Adjustments As Adjusted
------ -------------- ----------- -----------
<S> <C> <C> <C> <C>
CURRENT ASSETS
Cash and cash equivalents.......... $ 12,133 $48,763 A $ 12,133
(48,763)B
520 A
(520)B
Accounts receivable................ 343,393 -- 343,393
Inventory.......................... 55,707 -- 55,707
Prepaid expenses and other......... 2,111 -- 2,111
---------- ------- ----------
Total current assets............. 413,344 -- 413,344
---------- ------- ----------
PROPERTY AND EQUIPMENT
Crude oil pipeline, gathering and
terminal assets................... 507,770 -- 507,770
Other property and equipment....... 2,209 -- 2,209
---------- ------- ----------
509,979 -- 509,979
Less allowance for depreciation and
amortization...................... (6,432) -- (6,432)
---------- ------- ----------
503,547 -- 503,547
---------- ------- ----------
OTHER ASSETS
Pipeline linefill.................. 70,572 -- 70,572
Other.............................. 19,323 -- 19,323
---------- ------- ----------
$1,006,786 $ -- $1,006,786
========== ======= ==========
<CAPTION>
LIABILITIES AND PARTNERS' CAPITAL
---------------------------------
<S> <C> <C> <C> <C>
CURRENT LIABILITIES
Accounts payable and other current
liabilities....................... $ 370,500 $ -- $ 370,500
Due to affiliates.................. 16,482 -- 16,482
Notes payable and current
maturities of long-term debt...... 22,650 -- 22,650
---------- ------- ----------
Total current liabilities........ 409,632 -- 409,632
LONG-TERM LIABILITIES
Bank debt.......................... 289,350 (49,036)B 240,314
Other.............................. 1,264 -- 1,264
---------- ------- ----------
Total liabilities................ 700,246 (49,036) 651,210
---------- ------- ----------
PARTNERS' CAPITAL
Common unitholders (20,059,239
units outstanding, 22,659,239
pro forma)........................ 259,184 48,516 A 307,700
Class B Common unitholders
(1,307,190 units outstanding)..... 25,295 -- 25,295
Subordinated unitholders
(10,029,619 units outstanding).... 20,546 -- 20,546
General Partner.................... 1,515 520 A 2,035
---------- ------- ----------
306,540 49,036 355,576
---------- ------- ----------
$1,006,786 $ -- $1,006,786
========== ======= ==========
</TABLE>
See notes to pro forma consolidated financial statements.
F-4
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED STATEMENT OF INCOME (unaudited)
For the Six Months Ended June 30, 1999
(in thousands, except per unit data)
<TABLE>
<CAPTION>
Historical
---------------------------
Scurlock
Permian
Businesses
------------
Three Months
Plains All Ended
American March 31, Pro forma Offering Pro Forma
Pipeline, L.P. 1999 Adjustments Pro Forma Adjustments As Adjusted
-------------- ------------ ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
REVENUES................ $1,318,284 $775,331 $ (493)C $1,705,586 $ -- $1,705,586
(38,535)D
(476,743)E
127,742 F
COST OF SALES AND
OPERATIONS............. 1,272,244 763,511 (94)C 1,649,327 -- 1,649,327
(759)G
(496)H
(38,535)D
(474,803)E
(664)I
2,052 J
126,871 F
TAXES OTHER THAN INCOME
TAXES.................. -- 757 (928)E -- -- --
171 F
INVENTORY MARKET
VALUATION CREDIT....... -- (10,014) 515 K (9,499) -- (9,499)
---------- -------- -------- ---------- ------- ----------
Gross Margin............ 46,040 21,077 (1,359) 65,758 -- 65,758
---------- -------- -------- ---------- ------- ----------
EXPENSES
General and
administrative......... 7,947 7,956 (443)C 16,791 -- 16,791
(341)G
(313)I
1,985 F
Depreciation and
amortization........... 6,671 2,952 (59)C 8,680 -- 8,680
2,009 L
(3,783)M
890 F
---------- -------- -------- ---------- ------- ----------
Total expenses.......... 14,618 10,908 (55) 25,471 -- 25,471
---------- -------- -------- ---------- ------- ----------
Operating income........ 31,422 10,169 (1,304) 40,287 -- 40,287
Interest expense........ 7,913 -- 2,998 N 10,911 (1,849)B 9,062
Other expense........... 410 -- -- 410 410
Interest and other
income................. (287) -- 547 C (768) -- (768)
(1,012)E
(16)F
---------- -------- -------- ---------- ------- ----------
NET INCOME.............. $ 23,386 $ 10,169 $ (3,821) $ 29,734 $ 1,849 $ 31,583
========== ======== ======== ========== ======= ==========
BASIC AND DILUTED NET
INCOME PER LIMITED
PARTNER UNIT........... $ 0.75 $ 0.93 $ 0.91
========== ========== ==========
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING... 30,450 31,396 33,996
========== ========== ==========
</TABLE>
See notes to pro forma consolidated financial statements.
F-5
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED STATEMENT OF INCOME (unaudited)
For the Year Ended December 31, 1998
(in thousands, except per unit data)
<TABLE>
<CAPTION>
Historical
-------------------------------------------------
Plains All American
Pipeline, L.P. Wingfoot
-------------------------- ----------
January 1, November 23,
1998 to 1998 to Scurlock Six Months
November 22, December 31, Permian Ended June Pro Forma Offering Pro Forma
1998 1998 Businesses 30, 1998 Adjustments Pro Forma Adjustments As Adjusted
------------- ------------ ---------- ---------- ----------- ---------- ----------- -----------
(Predecessor)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
REVENUES........... $953,244 $176,445 $3,773,536 $374,654 $ (2,502)C $2,817,051 $ -- $2,817,051
(103,242)D
(2,419,594)E
62,995 F
1,515 O
COST OF SALES AND
OPERATIONS........ 922,263 168,946 3,742,276 344,538 (1,451)C 2,710,157 -- 2,710,157
(3,254)G
(1,460)H
(103,242)D
(2,416,155)E
(2,781)I
515 J
59,962 F
TAXES OTHER THAN
INCOME TAXES...... -- -- 2,653 -- (2,653)E -- -- --
INVENTORY MARKET
VALUATION CHARGE.. -- -- 10,014 -- (515)K 9,499 -- 9,499
-------- -------- ---------- -------- ----------- ---------- ------ ----------
Gross Margin....... 30,981 7,499 18,593 30,116 10,206 97,395 -- 97,395
-------- -------- ---------- -------- ----------- ---------- ------ ----------
EXPENSES
General and
administrative.... 4,526 771 31,033 1,053 (585)C 34,183 -- 34,183
(1,023)G
(1,743)I
151 F
Depreciation and
amortization...... 4,179 1,192 11,136 6,808 (248)C 17,328 -- 17,328
11,957 L
(18,721)M
1,025 F
-------- -------- ---------- -------- ----------- ---------- ------ ----------
Total expenses.. 8,705 1,963 42,169 7,861 (9,187) 51,511 -- 51,511
-------- -------- ---------- -------- ----------- ---------- ------ ----------
Operating income
(loss)........... 22,276 5,536 (23,576) 22,255 19,393 45,884 -- 45,884
Interest
expense.......... 8,492 1,371 -- -- 9,118 N 22,109 (4,003) B 18,106
12,224 P --
(9,096)Q
Related party
interest
expense.......... 2,768 -- -- 21,929 (21,929)R -- -- --
(2,768)Q
Interest and
other income..... (572) (12) -- -- (65)C (1,435) -- (1,435)
(786)E
-------- -------- ---------- -------- ----------- ---------- ------ ----------
Net income (loss)
before provision
in lieu of
income taxes..... 11,588 4,177 (23,576) 326 32,695 25,210 4,003 29,213
Provision in lieu
of income
taxes............ 4,563 -- -- 84 419 F -- -- --
(5,066)S
-------- -------- ---------- -------- ----------- ---------- ------ ----------
NET INCOME (LOSS).. $ 7,025 $ 4,177 $ (23,576) $ 242 $ 37,342 $ 25,210 $4,003 $ 29,213
======== ======== ========== ======== =========== ========== ====== ==========
BASIC AND DILUTED
NET INCOME (LOSS)
PER LIMITED
PARTNER UNIT...... $ 0.40 $ 0.14 $ 0.79 $ 0.84
======== ======== ========== ==========
WEIGHTED AVERAGE
NUMBER OF UNITS
OUTSTANDING....... 17,004 30,089 31,396 33,996
======== ======== ========== ==========
</TABLE>
See notes to pro forma consolidated financial statements.
F-6
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
In addition to the pro forma adjustments below, PAA estimates that certain
costs which are included in the historical financial statements of Scurlock
will not be incurred by PAA in its operations of Scurlock. Such amounts include
(i) approximately $1.4 million of severance costs included in the Scurlock
historical statement of operations for the year ended December 31, 1998 related
to staff reductions implemented by Scurlock in the fourth quarter of 1998 for
employees that PAA does not plan to replace, (ii) approximately $2.5 million of
compensation and benefits expense related to the staff reductions discussed in
item (i) which are included in the Scurlock historical statement of operations
for the year ended December 31 1998, and (iii) approximately $3.5 million and
$1.1 million which are reflected in the Scurlock historical statement of
operations for the year ended December 31, 1998 and the four months ended April
30, 1999, respectively, for amounts of corporate overhead allocated by MAP to
Scurlock.
Pro Forma Adjustments
Offering
A. Reflects the estimated net proceeds to the Partnership of $48.7 million
from the issuance and sale of 2.6 million Common Units at an offering price of
$19.8125 per Common Unit, net of underwriters' discounts and commissions and
offering expenses of approximately $2.8 million. In addition, reflects the
General Partner's capital contribution of approximately $0.5 million.
B. Reflects the repayment of approximately $49.0 million of debt outstanding
under Plains Scurlock's credit facility at June 30, 1999, plus a prepayment
penalty of $246,000, and the related reduction in interest expense for the six
months ended June 30, 1999 and the year ended December 31, 1998.
Acquisitions and Initial Public Offering
C. Reflects the elimination of revenues and expenses associated with certain
Scurlock assets that were not purchased by PAA.
D. Reflects the elimination of historical sales and purchases between
Scurlock and PAA.
E. Reflects the reclassification of certain of Scurlock's items to conform
to the classification of such items in PAA's historical financial statements.
In addition, in order to make the Scurlock financial data consistent with that
of PAA, purchases and sales have been adjusted to exclude buy/sell activity
where like volumes are purchased and sold with the same customer with no effect
on net income.
F. The historical information of the Partnership for the six months ended
June 30, 1999, includes the results of operations of Scurlock from May 1, 1999,
the effective date of the Scurlock Acquisition, through June 30, 1999. The All
American Acquisition was completed on July 30, 1998 and, as a result, the
historical financial information of the Predecessor for the period ending
November 22, 1998, includes the results of operations of Wingfoot from July 30,
1998, through November 22, 1998. These pro forma amounts reflect the results of
operations for the periods not otherwise included in the historical financial
information of the Partnership or Scurlock and the Predecessor or Wingfoot for
their respective periods.
G. Reflects the reduction in Scurlock and Wingfoot compensation and benefits
expense due to staff terminations implemented by the Predecessor and PAA at the
acquisition dates. PAA has no plans to replace these personnel. Such amounts
reflect the historical compensation expenses incurred by Scurlock and Wingfoot.
The termination of personnel is not expected to adversely impact PAA's revenues
or costs.
H. Reflects the cost reduction for services provided to Scurlock by MAP
related to the operation of certain pipeline assets. The Scurlock Acquisition
agreement provides for a reduced cost for such services subsequent to the
acquisition date.
F-7
<PAGE>
I. Reflects the elimination of expenses associated with MAP's profit
sharing and post retirement pension, health and benefit plans in which
Scurlock's employees are no longer entitled to participate so that cost of
sales and operations and general and administrative expense reflect the
ongoing cost of employee benefits to PAA.
J. Reflects the restatement of Scurlock's inventory at average cost, which
is the inventory costing method utilized by PAA. Scurlock utilized the LIFO
method to determine inventory cost.
K. Reflects the adjustment of the historical market valuation charge/credit
reflected in Scurlock's historical financial statements to reflect such
amounts based on the average cost inventory method utilized by PAA.
L. Reflects pro forma depreciation and amortization expense based on the
purchase price of the Scurlock assets by PAA and the Wingfoot assets by the
Predecessor. The pro forma composite useful depreciable life of the Scurlock
and Wingfoot assets acquired is 23 and 36 years, respectively. Debt issue
costs incurred in connection with the acquisitions are amortized using the
straight-line method over the term of the related debt.
M. Reflects the elimination of historical Scurlock and Wingfoot
depreciation and amortization expense.
N. Reflects pro forma interest expense on (i) borrowings of approximately
$92 million under Plains Scurlock's credit facility and (ii) borrowings of $25
million under PAA's existing credit facility. PAA has entered into a series of
21 month interest rate collars, which provide for a floor of 5.04% and a
ceiling of 6.5% on a notional principal amount of $90 million of the LIBOR
portion outstanding under Plains Scurlock's credit facility. Pro forma
interest expense was calculated based on a composite annual interest rate of
7.8%. The effect of a 1/8% change in the pro forma interest rate would be
approximately $150,000 for the year ended December 31, 1998 and $49,000 for
the four month period ended April 30, 1999.
O. Reflects the pro forma revenues from a marketing agreement entered into
upon consummation of the formation of the Partnership pursuant to which the
Partnership markets all of Plains Resources' crude oil production for a fee of
$0.20 per barrel. Pro forma revenues from such marketing agreement were
calculated based on Plains Resources historical crude oil production volumes
which were marketed by the Plains Midstream Subsidiaries.
P. Reflects pro forma interest expense on borrowings of $175 million
assumed from the Plains Midstream Subsidiaries in connection with the IPO. Pro
forma interest expense was calculated based on an annual interest rate of
6.99%. This average interest rate gives effect to a series of 10-year interest
rate swaps to fix the London Interbank Offering Rate portion of the interest
rate at a weighted average rate of 5.24% (6.99% after giving effect to the
weighted average interest rate margin).
Q. Reflects the elimination of historical interest expense on the All
American Acquisition indebtedness and loans from Plains Resources to the
Plains Midstream Subsidiaries. Such loans were not assumed by the Partnership.
R. Reflects the elimination of interest expense on loans from Goodyear to
Wingfoot. In connection with the All American Acquisition, Goodyear made a
capital contribution of $866.1 million to Wingfoot. Concurrently, the related
party debt and accrued interest of approximately $865.2 million was repaid in
full to Goodyear on June 15, 1998.
S. Reflects the elimination of the historical income tax provision as
income taxes will be borne by the partners and not the Partnership.
Pro Forma Net Income Per Unit
Pro forma net income per Unit is determined by dividing the pro forma net
income that would have been allocated to the Common and Subordinated
Unitholders, which is 98% of pro forma net income, by the number of Common and
Subordinated Units expected to be outstanding at the closing of the Offering.
For purposes of this calculation the Minimum Quarterly Distribution ("MQD")
was assumed to have been paid to both Common and Subordinated Unitholders and
the number of Common and Subordinated Units outstanding was assumed to have
been outstanding the entire period. Pursuant to the partnership agreement, to
the extent that the MQD is exceeded, the General Partner is entitled to
certain incentive distributions which will result in less income
proportionately being allocated to the Common and Subordinated Unitholders.
Basic and diluted pro forma net income per Unit are equal as there are no
dilutive Units.
F-8
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
------------ -----------
(unaudited)
ASSETS
------
<S> <C> <C>
CURRENT ASSETS
Cash and cash
equivalents.............. $ 5,503 $ 12,133
Accounts receivable....... 119,514 343,393
Inventory................. 37,711 55,707
Prepaid expenses and
other.................... 1,101 2,111
-------- ----------
Total current assets...... 163,829 413,344
-------- ----------
PROPERTY AND EQUIPMENT
Crude oil pipeline,
gathering and terminal
assets................... 378,254 507,770
Other property and
equipment................ 581 2,209
-------- ----------
378,835 509,979
Less allowance for
depreciation and
amortization............. (799) (6,432)
-------- ----------
378,036 503,547
-------- ----------
OTHER ASSETS
Pipeline linefill......... 54,511 70,572
Other..................... 10,810 19,323
-------- ----------
$607,186 $1,006,786
======== ==========
<CAPTION>
LIABILITIES AND PARTNERS'
CAPITAL
-------------------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable and other
current liabilities...... $136,980 $ 370,500
Due to affiliates......... 7,768 16,482
Notes payable and current
maturities of long-term
debt..................... 9,750 22,650
-------- ----------
Total current
liabilities.............. 154,498 409,632
LONG-TERM LIABILITIES
Bank debt................. 175,000 289,350
Other..................... 45 1,264
-------- ----------
Total liabilities......... 329,543 700,246
-------- ----------
PARTNERS' CAPITAL
Common unitholders
(20,059,239 units
outstanding at December
31, 1998 and
June 30, 1999).............. 256,997 259,184
Class B Common unitholders
(1,307,190 units
outstanding at June 30,
1999).................... -- 25,295
Subordinated unitholders
(10,029,619 units
outstanding at December
31, 1998 and June 30,
1999)....................... 19,454 20,546
General Partner........... 1,192 1,515
-------- ----------
277,643 306,540
-------- ----------
$607,186 $1,006,786
======== ==========
</TABLE>
See notes to consolidated and combined financial statements.
F-9
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
(unaudited) (in thousands, except per unit data)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- -------------------------
1998 1999 1998 1999
------------- -------- ------------- -----------
(Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
REVENUES................... $163,222 $862,524 $330,683 $ 1,318,284
COST OF SALES AND
OPERATIONS................ 158,026 836,312 321,483 1,272,244
-------- -------- -------- -----------
Gross Margin............... 5,196 26,212 9,200 46,040
-------- -------- -------- -----------
EXPENSES...................
General and
administrative............ 1,055 5,769 2,041 7,947
Depreciation and
amortization.............. 318 3,840 621 6,671
-------- -------- -------- -----------
Total expenses............. 1,373 9,609 2,662 14,618
-------- -------- -------- -----------
Operating income........... 3,823 16,603 6,538 31,422
Interest expense........... 179 4,720 328 7,913
Related party interest
expense................... 750 -- 1,500 --
Other expense.............. -- -- -- 410
Interest and other income.. (404) (190) (581) (287)
-------- -------- -------- -----------
Net income before provision
in lieu of income taxes... 3,298 12,073 5,291 23,386
Provision in lieu of income
taxes..................... 1,284 -- 2,037 --
-------- -------- -------- -----------
NET INCOME................. $ 2,014 $ 12,073 $ 3,254 $ 23,386
======== ======== ======== ===========
NET INCOME--LIMITED
PARTNERS.................. $ 1,974 $ 11,832 $ 3,189 $ 22,918
======== ======== ======== ===========
NET INCOME--GENERAL
PARTNER................... $ 40 $ 241 $ 65 $ 468
======== ======== ======== ===========
BASIC AND DILUTED NET
INCOME PER LIMITED PARTNER
UNIT...................... $ 0.12 $ 0.38 $ 0.19 $ 0.75
======== ======== ======== ===========
WEIGHTED AVERAGE UNITS
OUTSTANDING............... 17,004 30,807 17,004 30,450
======== ======== ======== ===========
</TABLE>
See notes to consolidated and combined financial statements.
F-10
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(unaudited) (in thousands)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
----------------------
1998 1999
------------- --------
(Predecessor)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................................ $ 3,254 $ 23,386
Items not affecting cash flows from operating activi-
ties:
Depreciation and amortization....................... 621 6,671
Change in payable in lieu of deferred taxes......... 783 --
Other non cash items................................ -- 182
Change in assets and liabilities:
Accounts receivable................................. 6,673 (74,788)
Inventory........................................... (9,066) (1,176)
Prepaid expenses and other.......................... 146 966
Accounts payable and other current liabilities...... (5,395) 60,233
Pipeline linefill................................... -- (3)
------- --------
Net cash provided by (used in) operating activities... (2,984) 15,471
------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Costs incurred in connection with acquisitions (see
Note 2).............................................. -- (141,971)
Additions to property and equipment................... (455) (4,832)
Disposals of property and equipment................... 1 155
Additions to other assets............................. (52) (158)
------- --------
Net cash used in investing activities................. (506) (146,806)
------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from affiliates.............................. 4,166 8,731
Proceeds from issuance of Class B Common Units........ -- 25,000
Proceeds from long-term debt.......................... -- 187,621
Proceeds from short-term debt......................... 17,900 24,150
Principal payments of long-term debt.................. -- (72,621)
Principal payments of short-term debt................. (18,000) (11,900)
Costs incurred for issuance of long-term debt in
connection with acquisitions......................... -- (3,527)
Capital contribution from General Partner............. -- 252
Capital contribution from parent...................... 28,701 --
Distributions to unitholders.......................... -- (19,741)
------- --------
Net cash provided by financing activities............. 32,767 137,965
------- --------
Net increase in cash and cash equivalents............. 29,277 6,630
Cash and cash equivalents, beginning of period........ 2 5,503
------- --------
Cash and cash equivalents, end of period.............. $29,279 $ 12,133
======= ========
</TABLE>
See notes to consolidated and combined financial statements.
F-11
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (unaudited)
Note 1--Organization and Accounting Policies
Plains All American Pipeline, L.P. (the "Partnership" or "PAA") is a
Delaware limited partnership 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"). On November 23, 1998, the
Partnership completed the initial public offering ("IPO") and the transactions
whereby the Partnership became the successor to the business of the
Predecessor. The operations of the Partnership are conducted through Plains
Marketing, L.P., All American Pipeline, L.P. and Plains Scurlock Permian, L.P.
("Plains Scurlock"). Plains All American Inc. ("PAAI"), a wholly owned
subsidiary of Plains Resources, is the general partner ("General Partner") of
the Partnership. The Partnership is engaged in interstate and intrastate crude
oil pipeline transportation and crude oil gathering and marketing activities
and terminalling and storage activities. The Partnership's operations are
primarily conducted in California, Texas, Oklahoma, Louisiana and the Gulf of
Mexico.
The accompanying financial statements and related notes present the
consolidated financial position as of June 30, 1999, of the Partnership and the
results of its operations for the three and six months ended June 30, 1999 and
its cash flows for the six months ended June 30, 1999. The combined financial
statements of the Predecessor include the accounts of the Plains Midstream
Subsidiaries.
The accompanying unaudited financial statements have been prepared in
accordance with the instructions for interim financial reporting as prescribed
by the Securities and Exchange Commission ("SEC"). All material adjustments,
consisting only of normal recurring adjustments, which in the opinion of
management were necessary for a fair statement of the results for the interim
periods, have been reflected. The results for the three and six months ended
June 30, 1999 are not necessarily indicative of the final results to be
expected for the full year. Certain reclassifications have been made to the
prior year statements to conform to the current year presentation. All
significant intercompany transactions have been eliminated.
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, 2000. SFAS 133 requires that all
derivative instruments be recorded on the balance sheet at their fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other comprehensive income, depending on whether a derivative is
designated as part of a hedge transaction and, if so, the type of hedge
transaction. For fair value hedge transactions in which 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 2001. The Partnership has not yet determined the effect
that the adoption of SFAS 133 will have on its financial position or results of
operations.
Note 2--Acquisitions
Scurlock Acquisition
On May 12, 1999, Plains Scurlock, a limited partnership of which PAAI is the
general partner and Plains Marketing, L.P. is the limited partner, completed
the acquisition of Scurlock Permian LLC ("Scurlock") and
F-12
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (unaudited)--
(Continued)
certain other pipeline assets (the "Scurlock Acquisition") from Marathon
Ashland Petroleum LLC ("MAP"). Including working capital adjustments and
associated closing and financing costs, the cash purchase price was
approximately $141 million.
Scurlock, previously a wholly owned subsidiary of MAP, is engaged in crude
oil transportation, gathering and marketing, operating with more than 2,400
miles of active pipelines, numerous storage terminals and a fleet of more than
250 trucks. Its largest asset is an 800-mile pipeline and gathering system
located in the Spraberry Trend in West Texas that extends into Andrews,
Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets
acquired also include approximately 1.0 million barrels of crude oil linefill.
Financing for the Scurlock Acquisition was provided through (i) a borrowing
of approximately $92 million under Plains Scurlock's limited recourse bank
facility with BankBoston, N.A. (the "Plains Scurlock Credit Facility"), (ii)
the sale to the General Partner of 1.3 million Class B Common Units ("Class B
Units") of PAA at $19.125 per unit, the price equal to the market value of
PAA's common units ("Common Units") on May 12, 1999, for a total cash
consideration of $25 million and (iii) a $25 million draw under PAA's existing
revolving credit agreement.
The Plains Scurlock Credit Facility consists of (i) a five-year $126.6
million term loan and (ii) a three-year $35 million revolving credit facility.
The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains Marketing,
L.P. and All American Pipeline, L.P. and is secured by the assets acquired.
Borrowings under the term loan bear interest at the London Interbank Offering
Rate ("LIBOR") plus 3% and under the revolving credit facility at LIBOR plus
2.75%. A commitment fee equal to one-half of one percent per year is charged on
the unused portion of the revolving credit facility. The revolving credit
facility, which may be used for borrowings or letters of credit to support
crude oil purchases, matures in May 2002. The term loan provides for principal
amortization of $0.7 million annually beginning May 2000, with a final maturity
of May 2004. As of June 30, 1999, letters of credit of approximately $15.2
million were outstanding under the revolver and borrowings of $90 million were
outstanding under the term loan.
The Class B Units are initially pari passu with Common Units with respect to
distributions, and after six months are convertible into Common Units upon
approval of a majority of Common Unitholders. After such six month period, the
Class B Unitholder may request that PAA call a meeting of Common Unitholders to
consider approval of the conversion of Class B Units into Common Units. If the
approval of such conversion by the Common Unitholders is not obtained within
120 days of such request (the "Initial Approval Period"), the Class B
Unitholders will be entitled to receive distributions, on a per Unit basis,
equal to 110% of the amount of distributions paid on a Common Unit, with such
distribution right increasing to 115% if such approval is not secured within 90
days after the end of the Initial Approval Period. Except for the vote to
approve the conversion, Class B Units have the same voting rights as the Common
Units.
The assets, liabilities and results of operations of Scurlock are included
in the Consolidated Financial Statements of the Partnership effective May 1,
1999. The Scurlock Acquisition has been accounted for using the purchase method
of accounting and the purchase price was allocated in accordance with
Accounting Principles Board Opinion No. 16, Business Combinations ("APB 16") as
follows:
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Crude oil pipeline, gathering and terminal assets.......... $124,615
Other property and equipment............................... 1,546
Pipeline linefill.......................................... 16,057
Other assets (debt issue costs)............................ 3,100
Environmental accrual...................................... (1,000)
Net working capital items.................................. (3,090)
--------
Cash paid.................................................. $141,228
========
</TABLE>
F-13
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (unaudited)--
(Continued)
The purchase price allocation was based on preliminary estimates of fair
value and is subject to adjustment as additional information becomes available
and is evaluated. The purchase accounting entries include a $1.0 million
accrual for estimated environmental remediation costs. Under the agreement for
the sale of Scurlock by MAP to Plains Scurlock, MAP has agreed to indemnify and
hold harmless Scurlock and Plains Scurlock for claims, liabilities and losses
(collectively "Losses") resulting from any act or omission attributable to
Scurlock's business or properties occurring prior to the date of the closing of
such sale to the extent the aggregate amount of such Losses exceed $1.0
million; provided however, that claims for such Losses must individually exceed
$25,000 and must be asserted by Scurlock against MAP on or before May 15, 2003.
Chevron Asset Acquisition
On July 15, 1999, Plains Scurlock completed the acquisition of a West Texas
crude oil pipeline and gathering system from Chevron Pipe Line Company for
approximately $36.6 million, including transaction costs (the "Chevron Asset
Acquisition"). The principal assets acquired include approximately 450 miles of
crude oil transmission mainlines, approximately 340 miles of associated
gathering and lateral lines and approximately 2.9 million barrels of crude oil
storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and
Winkler Counties, Texas. Financing for the Chevron Asset Acquisition was
provided by a draw of $36.6 million under the term loan portion of the Plains
Scurlock Credit Facility.
Chevron U.S.A. Inc., which currently transports approximately 26,000 barrels
of crude oil per day on the system, will continue to transport its equity crude
oil production from the region on the system under a twelve-year contractual
arrangement.
Pro Forma Results for the Scurlock Acquisition and All American Pipeline
Acquisition
The following unaudited pro forma data is presented to show pro forma
revenues, net income and basic and diluted net income per limited partner unit
as if the Scurlock Acquisition, which was effective May 1, 1999, and the
acquisition of the All American Pipeline and the Celeron Gathering System (the
"All American Acquisition"), which was effective July 30, 1998 had both
occurred on January 1, 1998. The results for the six month period 1998 do not
reflect certain pro forma adjustments as if the Partnership had been formed on
January 1, 1998.
<TABLE>
<CAPTION>
Six Months Ended June
30,
---------------------
1998 1999
---------- ----------
(in thousands)
<S> <C> <C>
Revenues.......................................... $2,440,595 $2,367,672
========== ==========
Net income........................................ $ 6,401 $ 31,250
========== ==========
Basic and diluted net income per limited partner
unit............................................. $ 0.34 $ 0.98
========== ==========
</TABLE>
Note 3--Distributions
On February 12, 1999, the Partnership paid a cash distribution of $0.193 per
unit on its outstanding Common Units and Subordinated Units. The distribution
was paid to Unitholders of record at the close of business on January 29, 1999.
The total distribution paid was approximately $5.9 million, with approximately
$2.5 million paid to the Partnership's public Unitholders, and the remainder
paid to the General Partner for its limited partner and general partner
interests. The distribution represented a partial quarterly distribution for
the 39-day period from November 23, 1998, the closing of the IPO, through
December 31, 1998.
On May 14, 1999, the Partnership paid a cash distribution of $0.45 per unit
on its outstanding Common Units and Subordinated Units. The distribution was
paid to holders of record of Common Units and Subordinated Units at the close
of business on May 3, 1999. The total distribution paid was approximately $13.8
million, with approximately $5.9 million paid to the Partnership's public
Unitholders, and the remainder
F-14
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (unaudited)--
(Continued)
paid to the General Partner for its limited partner and general partner
interests. This distribution was the first full quarterly distribution since
the Partnership was formed.
On July 22, 1999, the Partnership declared a cash distribution of $0.4625
per Unit on its outstanding Common Units, Class B Units and Subordinated Units.
The distribution is payable on August 13, 1999, to holders of record of such
Units on August 3, 1999. The total distribution to be paid is approximately
$14.9 million, with approximately $6.1 million to be paid to the Partnership's
public Unitholders and the remainder to be paid to the General Partner for its
limited and general partner interests. This distribution represents an increase
of $.0125 per unit over the minimum quarterly distribution of $0.45 per unit.
Note 4--Operating Segments
The Partnership's operations consist of two operating segments: (i) Pipeline
Operations--engages in interstate and intrastate crude oil pipeline
transportation and related gathering and marketing activities; (ii) Marketing,
Gathering, Terminalling and Storage Operations--engages in crude oil marketing
and gathering, terminalling and storage activities other than related to
Pipeline Operations. Prior to the July 1998 All American Acquisition, the
Predecessor had only marketing, gathering, terminalling and storage operations;
thus, no prior periods are presented. The Partnership evaluates segment
performance based on gross margin, gross profit and income before income taxes
and extraordinary items.
The following table summarizes segment revenues, gross margin, gross profit
and income before income taxes and extraordinary items:
<TABLE>
<CAPTION>
Marketing,
Gathering,
Terminalling
(In thousands) Pipeline & Storage Total
- -------------- -------- ------------ ----------
<S> <C> <C> <C>
Three Months Ended June 30, 1999
Revenues:
External Customers......................... $223,128 $639,396 $ 862,524
Intersegment (a)........................... 19,470 (55) 19,415
Other...................................... 29 161 190
-------- -------- ----------
Total revenues of reportable segments.... $242,627 $639,502 $ 882,129
======== ======== ==========
Segment gross margin (b)..................... $ 12,917 $ 13,295 $ 26,212
Segment gross profit (c)..................... $ 12,189 $ 8,254 $ 20,443
Income before income taxes and extraordinary
items....................................... $ 6,035 $ 6,038 $ 12,073
Six Months Ended June 30, 1999
Revenues:
External Customers......................... $377,615 $940,669 $1,318,284
Intersegment (a)........................... 34,775 -- 34,775
Other...................................... 95 192 287
-------- -------- ----------
Total revenues of reportable segments.... $412,485 $940,861 $1,353,346
======== ======== ==========
Segment gross margin (b)..................... $ 24,936 $ 21,104 $ 46,040
Segment gross profit (c)..................... $ 23,413 $ 14,680 $ 38,093
Income before income taxes and extraordinary
items....................................... $ 11,509 $ 11,877 $ 23,386
</TABLE>
- --------
(a) Intersegment sales were conducted on an arm's-length basis.
(b) Gross margin is calculated as revenues less cost of sales and operations
expenses.
(c) Gross profit is calculated as revenues less cost of sales and operations
and general and administrative expenses.
F-15
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of the General Partner and the Unitholders of
Plains All American Pipeline, L.P.
In our opinion, the accompanying consolidated balance 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-16
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED BALANCE SHEETS
(in thousands, except unit data)
<TABLE>
<CAPTION>
December 31,
----------------------
1997 1998
------------- --------
(Predecessor)
ASSETS
------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents............................. $ 2 $ 5,503
Accounts receivable................................... 96,319 119,514
Prepaid expenses and other............................ 197 1,101
Inventory............................................. 18,909 37,711
-------- --------
Total current assets.................................. 115,427 163,829
-------- --------
PROPERTY AND EQUIPMENT
Crude oil pipeline, gathering and terminal assets..... 35,591 378,254
Other property and equipment.......................... 698 581
-------- --------
36,289 378,835
Less allowance for depreciation and amortization...... (3,903) (799)
-------- --------
32,386 378,036
-------- --------
OTHER ASSETS
Pipeline linefill..................................... -- 54,511
Other................................................. 1,806 10,810
-------- --------
$149,619 $607,186
======== ========
<CAPTION>
LIABILITIES AND EQUITY
----------------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable and other current liabilities........ $ 86,415 $135,713
Interest payable...................................... 50 1,267
Due to affiliates..................................... 8,945 7,768
Notes payable......................................... 18,000 9,750
-------- --------
Total current liabilities............................. 113,410 154,498
LONG-TERM LIABILITIES
Bank debt............................................. -- 175,000
Due to affiliates..................................... 28,531 --
Payable in lieu of deferred taxes..................... 1,703 --
Other................................................. -- 45
-------- --------
Total liabilities..................................... 143,644 329,543
-------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 8)
COMBINED EQUITY....................................... 5,975 --
-------- --------
PARTNERS' CAPITAL
Common unitholders (20,059,239 units outstanding)..... -- 256,997
Subordinated unitholders (10,029,619 units
outstanding)......................................... -- 19,454
General partner....................................... -- 1,192
-------- --------
-- 277,643
-------- --------
$149,619 $607,186
======== ========
</TABLE>
See notes to consolidated and combined financial statements.
F-17
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
(in thousands, except per unit and unit data)
<TABLE>
<CAPTION>
January 1, November 23,
Year Ended December 31, 1998 To 1998 To
--------------------------- November 22, December 31,
1996 1997 1998 1998
------------- ------------- ------------- ------------
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
REVENUES................ $ 531,698 $ 752,522 $ 953,244 $ 176,445
COST OF SALES AND
OPERATIONS............. 522,167 740,042 922,263 168,946
---------- ---------- ---------- ----------
Gross Margin............ 9,531 12,480 30,981 7,499
---------- ---------- ---------- ----------
EXPENSES
General and
administrative......... 2,974 3,529 4,526 771
Depreciation and
amortization........... 1,140 1,165 4,179 1,192
---------- ---------- ---------- ----------
Total expenses.......... 4,114 4,694 8,705 1,963
---------- ---------- ---------- ----------
Operating income........ 5,417 7,786 22,276 5,536
Interest expense........ -- 894 8,492 1,371
Related party interest
expense................ 3,559 3,622 2,768 --
Interest and other
income................. (90) (138) (572) (12)
---------- ---------- ---------- ----------
Net income before
provision in lieu of
income taxes........... 1,948 3,408 11,588 4,177
Provision in lieu of
income taxes........... 726 1,268 4,563 --
---------- ---------- ---------- ----------
NET INCOME.............. $ 1,222 $ 2,140 $ 7,025 $ 4,177
========== ========== ========== ==========
BASIC AND DILUTED NET
INCOME PER LIMITED
PARTNER UNIT........... $ 0.07 $ 0.12 $ 0.40 $ 0.14
========== ========== ========== ==========
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING... 17,003,858 17,003,858 17,003,858 30,088,858
========== ========== ========== ==========
</TABLE>
See notes to consolidated and combined financial statements.
F-18
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
January 1, November 23,
Year Ended December 31, 1998 To 1998 To
--------------------------- November 22, December 31,
1996 1997 1998 1998
------------- ------------- ------------- ------------
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
CASH FLOWS FROM
OPERATING ACTIVITIES
Net income.............. $ 1,222 $ 2,140 $ 7,025 $ 4,177
Items not affecting cash
flows from operating
activities:
Depreciation and
amortization......... 1,140 1,165 4,179 1,192
(Gain) loss on sale of
property and
equipment............ (34) (28) 117 --
Change in payable in
lieu of deferred
taxes................ 706 1,131 4,108 --
Other non cash items.. -- -- -- 45
Change in assets and
liabilities, net of
Acquisition:
Accounts receivable... (38,771) (10,415) 38,794 (10,203)
Inventory............. 435 (16,450) (3,336) (14,805)
Prepaid expenses and
other................ 41 (39) (1,296) (42)
Accounts payable and
other current
liabilities.......... 35,994 9,577 (30,511) 33,008
Interest payable...... -- 50 (39) 1,267
Pipeline linefill..... -- -- 2,343 (6,247)
------- ------- -------- --------
Net cash provided by
(used in) operating
activities........... 733 (12,869) 21,384 8,392
------- ------- -------- --------
CASH FLOWS FROM
INVESTING ACTIVITIES
Acquisition (see Note
2):.................... -- -- (394,026) --
Additions to property
and equipment.......... (3,346) (678) (5,528) (2,887)
Disposals of property
and equipment.......... 97 85 8 --
Additions to other
assets................. (36) (1,261) (65) (202)
------- ------- -------- --------
Net cash used in
investing activities... (3,285) (1,854) (399,611) (3,089)
------- ------- -------- --------
CASH FLOWS FROM
FINANCING ACTIVITIES
Advances from (payments
to) affiliates......... 2,759 (3,679) 3,349 (1,174)
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................... -- 39,000 30,600 1,150
Principal payments of
long-term debt......... -- -- (39,300) --
Principal payments of
short-term debt........ -- (21,000) (40,000) --
Capital contribution
from Parent............ -- -- 113,700 --
Dividend to Parent...... -- -- (3,557) --
------- ------- -------- --------
Net cash provided by
financing activities... 2,759 14,321 386,154 200
------- ------- -------- --------
Net increase (decrease)
in cash and cash
equivalents............ 207 (402) 7,927 5,503
Cash and cash
equivalents, beginning
of period.............. 197 404 2 --
------- ------- -------- --------
Cash and cash
equivalents, end of
period................. $ 404 $ 2 $ 7,929 $ 5,503
======= ======= ======== ========
</TABLE>
See notes to consolidated and combined financial statements.
F-19
<PAGE>
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)
<TABLE>
<CAPTION>
Total
Subordinated General Partners'
Common Units Units Partner Equity
--------------- ---------------- ------- ---------
Units Amount Units Amount Amount Amount
------ -------- ------ --------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Issuance of units to
public................. 13,085 $241,690 -- $ -- $ -- $ 241,690
Contribution of assets
and debt assumed....... 6,974 108,253 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
====== ======== ====== ========= ======= =========
</TABLE>
See notes to consolidated and combined financial statements.
F-20
<PAGE>
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. 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
F-21
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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 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.
F-22
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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
it 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.
The following is a summary of the components of property and equipment:
<TABLE>
<CAPTION>
December 31,
-----------------
1997 1998
------- --------
(in thousands)
<S> <C> <C>
Crude oil pipelines.................................... $ -- $268,219
Crude oil pipeline facilities.......................... -- 70,870
Crude oil storage and terminal facilities.............. 33,491 34,606
Trucking equipment, injection stations and other....... 2,798 5,140
------- --------
36,289 378,835
Less accumulated depreciation and amortization......... (3,903) (799)
------- --------
$32,386 $378,036
======= ========
</TABLE>
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:
<TABLE>
<CAPTION>
December 31,
---------------
1997 1998
------ -------
(in thousands)
<S> <C> <C>
Debt issue costs......................................... $ 232 $10,171
Goodwill and other....................................... 2,096 1,134
------ -------
2,328 11,305
Accumulated amortization................................. (522) (495)
------ -------
$1,806 $10,810
====== =======
</TABLE>
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.
F-23
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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
bases 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.
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.
F-24
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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 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
F-25
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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.
<TABLE>
<CAPTION>
Year January 1,
Ended 1998 to
December 31, November 22,
1997 1998
------------ ------------
(in thousands)
<S> <C> <C>
Revenues...................................... $1,744,840 $1,390,893
========== ==========
Net income (loss)............................. $ (17,039) $ 14,448
========== ==========
Basic and diluted net income (loss) per
limited partner unit......................... $ (0.98) $ 0.83
========== ==========
</TABLE>
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):
<TABLE>
<S> <C>
Crude oil pipeline, gathering and terminal assets............... $392,528
Other assets (debt issue costs)................................. 6,138
Net working capital items (excluding cash received of $7,481)... 1,498
--------
Cash paid....................................................... $400,164
========
</TABLE>
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-26
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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, 1997 and 1998, there were outstanding letters of credit of
approximately $38 million and $62 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.
F-27
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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
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
For 1996 and 1997, customers accounting for more than 10% of total sales are
as follows: 1996 Koch Oil Company ("Koch")--16% and Basis Petroleum Inc.
("Basis"), formerly Phibro Energy U.S.A., Inc. --11%; 1997--Koch--30%, Sempra
Energy Trading Corporation ("Sempra")--12% and Basis--11%. During the period
from January 1, 1998 to November 22, 1998, Sempra and 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.
No other customer accounted for as much as 10% of total sales during 1996, 1997
and 1998.
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
F-28
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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
$100.5 million, $101.2 million and $83.4 million for the purchase of these
products for the years ended December 31, 1996 and 1997 and for the period from
January 1, 1998 to November 22, 1998, 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 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 for the years ended December 31,
1996 and 1997 and during the period from January 1, 1998 to November 22, 1998.
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
F-29
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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 and 2000, 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.
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:
<TABLE>
<CAPTION>
December 31,
1998
----------------
Carrying Fair
Amount Value
-------- -------
(in thousands)
<S> <C> <C>
Unrealized loss on interest rate swaps.................. $ -- $(2,164)
</TABLE>
F-30
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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.
F-31
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
In March 1999, the Partnership signed a definitive agreement to acquire
Scurlock Permian LLC and certain other pipeline assets (See Note 14).
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):
<TABLE>
<S> <C>
Cash and cash equivalents....................................... $ 224
Accounts receivable............................................. 109,311
Inventory....................................................... 22,906
Prepaid expenses and other current assets ...................... 1,059
Property and equipment, net..................................... 375,948
Pipeline linefill............................................... 48,264
Intangible assets, net.......................................... 11,001
--------
Total assets conveyed......................................... 568,713
--------
Accounts payable and other current liabilities.................. 102,705
Due to affiliates............................................... 8,942
Bank debt....................................................... 183,600
--------
Total liabilities assumed..................................... 295,247
--------
Net assets assumed by the Partnership........................... $273,466
========
</TABLE>
Interest paid totaled $3.6 million and $4.5 million for the years ended
December 31, 1996 and 1997, respectively, and $8.5 million for the period from
January 1, 1998 through November 23, 1998 and $0.1 million for the period from
November 23, 1998 through December 31, 1998.
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
F-32
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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.
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
F-33
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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-34
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
The following summarizes segment revenues, gross margin, gross profit and
income before income taxes and extraordinary items.
<TABLE>
<CAPTION>
Marketing,
Gathering,
Terminalling
Pipeline & Storage Total
-------- ------------ ----------
(in thousands)
<S> <C> <C> <C>
January 1, 1998 to November 22, 1998
(Predecessor)
Revenues:
External Customers...................... $221,305 $755,496 $ 976,801(b)
Intersegment (a)........................ 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...................... $ 13,222 $ 17,759 $ 30,981(c)
Segment gross profit...................... 12,394 14,061 26,455(d)
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...................... $ 56,118 $122,785 $ 178,903(b)
Intersegment (a)........................ 2,029 429 2,458
Other................................... -- 12 12
-------- -------- ----------
Total revenues of reportable
segments............................. $ 58,147 $123,226 $ 181,373
======== ======== ==========
Segment gross margin...................... $ 3,546 $ 3,953 $ 7,499(c)
Segment gross profit...................... 3,329 3,399 6,728(d)
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.............................. 471,864 135,322 607,186
- -------------------------------------------------------------------------------
Combined Total For the Year Ended December
31, 1998
Revenues:
External Customers...................... $277,423 $878,281 $1,155,704(b)
Intersegment (a)........................ 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...................... $ 16,768 $ 21,712 $ 38,480(c)
Segment gross profit...................... 15,723 17,460 33,183(d)
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.............................. 471,864 135,322 607,186
</TABLE>
- --------
(a) Intersegment sales were conducted on an arm's-length basis.
(b) Differences between total segment revenues and consolidated revenues relate
to intersegment revenues.
(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.
F-35
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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:
<TABLE>
<CAPTION>
Year Ended January 1,
December 31, 1998 to
------------------- November 22,
1996 1997 1998
---- -------------- ------------
(in thousands)
<S> <C> <C> <C>
Federal
Current................................ $ 1 $ 38 $ 455
Deferred............................... 706 1,131 3,390
State
Current................................ 19 99 --
Deferred............................... -- -- 718
---- ------ ------
Total.................................... $726 $1,268 $4,563
==== ====== ======
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended January 1,
December 31, 1998 to
------------------- November 22,
1996 1997 1998
---- -------------- ------------
(in thousands)
<S> <C> <C> <C>
Provision at the statutory rate........ $682 $1,169 $4,056
State income tax, net of benefit for
federal deduction..................... 12 65 467
Permanent differences.................. 32 34 40
---- ------ ------
Total.................................. $726 $1,268 $4,563
==== ====== ======
</TABLE>
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):
<TABLE>
<S> <C>
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
========
</TABLE>
F-36
<PAGE>
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS--(Continued)
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, 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-37
<PAGE>
SCURLOCK PERMIAN BUSINESSES
BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
December 31, March 31,
1998 1999
------------ -----------
(unaudited)
ASSETS
------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents............................. $ 346 $ 36
Accounts receivable, net.............................. 259,368 243,998
Inventory............................................. 18,258 37,208
Other current assets.................................. 445 2,988
-------- --------
Total current assets.................................. 278,417 284,230
-------- --------
PROPERTY AND EQUIPMENT................................ 145,436 143,425
Less allowance for depreciation and amortization...... (13,621) (15,215)
-------- --------
131,815 128,210
-------- --------
OTHER ASSETS
Investments and long-term receivables................. 2,487 2,512
Other................................................. 1,892 1,706
-------- --------
$414,611 $416,658
======== ========
<CAPTION>
LIABILITIES AND PARENT COMPANY INVESTMENT
-----------------------------------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable...................................... $294,870 $301,440
Payroll and benefits payable.......................... 4,865 2,539
Other current liabilities............................. 9,731 6,498
-------- --------
Total current liabilities............................. 309,466 310,477
PARENT COMPANY INVESTMENT............................. 105,145 106,181
-------- --------
$414,611 $416,658
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-38
<PAGE>
SCURLOCK PERMIAN BUSINESSES
STATEMENTS OF OPERATIONS (unaudited)
(in thousands)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
--------------------
1998 1999
--------- ---------
<S> <C> <C>
REVENUES.................................................. $ 816,526 $ 775,331
COSTS AND EXPENSES
Cost of sales (excludes items shown below)................ 805,224 763,511
Selling, general and administrative expenses.............. 6,941 7,956
Depreciation and amortization............................. 2,847 2,952
Taxes other than income taxes............................. 1,393 757
Inventory market valuation charge (credit)................ 4,530 (10,014)
--------- ---------
Total costs and expenses.................................. 820,935 765,162
--------- ---------
NET INCOME (LOSS)......................................... $ (4,409) $ 10,169
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-39
<PAGE>
SCURLOCK PERMIAN BUSINESSES
STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
--------------------
1998 1999
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income (loss)......... $ (4,409) $ 10,169
Items not affecting cash
flows from operating
activities:
Depreciation and
amortization........... 2,847 2,952
Inventory market
valuation charge
(credit)............... 4,530 (10,014)
Gain on disposal of
assets................. -- (909)
Change in assets and
liabilities
Accounts receivable..... 20,059 14,886
Inventory............... (4,747) (8,936)
Accounts payable and
other current
liabilities............ (5,951) (1,342)
Other, net.............. (467) (524)
--------- ---------
Net cash provided by
operating activities... 11,862 6,282
--------- ---------
CASH FLOWS FROM INVESTING
ACTIVITIES
Disposal of assets........ -- 3,112
Capital expenditures...... (82) (546)
Affiliates--distributions
from (investments in).... 21 (25)
--------- ---------
Net cash (used in) pro-
vided by investing ac-
tivities............... (61) 2,541
--------- ---------
CASH FLOWS FROM FINANCING
ACTIVITIES
Net change in Parent
Company advances......... (11,554) (9,133)
--------- ---------
Net cash used in financing
activities............... (11,554) (9,133)
--------- ---------
Net increase (decrease) in
cash and cash
equivalents.............. 247 (310)
Cash and cash equivalents,
beginning of period...... 34 346
--------- ---------
Cash and cash equivalents,
end of period............ $ 281 $ 36
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-40
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO INTERIM FINANCIAL STATEMENTS (unaudited)
FOR THE THREE MONTHS ENDED MARCH 31, 1999
1. Scurlock Permian LLC (SPLLC) was a wholly owned subsidiary of Marathon
Ashland Petroleum LLC (MAP). MAP was formed effective January 1, 1998, and
is owned 62% by Marathon Oil Company (Marathon) and 38% by Ashland Inc.
(Ashland).
On March 17, 1999, MAP entered into an agreement with Plains Marketing,
L.P. (Plains) providing for the sale of MAP's membership interest in SPLLC
and certain other pipeline assets (collectively, the Scurlock Permian
Businesses or the Company) to Plains. This transaction was consummated on
May 12, 1999. The accompanying financial statements do not include any
adjustments that might result from the sale.
The accompanying financial statements pertain to the businesses that were
sold to Plains and represent a carve-out financial statement presentation
of a MAP operating unit as of December 31, 1998 and March 31, 1999, and for
the three months ended March 31, 1998 and 1999. The unaudited interim
financial statements reflect all adjustments, consisting of normal
recurring adjustments, which in the opinion of MAP's management are
necessary for a fair statement of the results for the interim periods
presented. The financial statements include allocations and estimates of
direct and indirect MAP corporate administrative costs attributable to the
Company. The methods by which such amounts are attributed or allocated are
deemed reasonable by MAP's management. The financial information herein is
not necessarily indicative of the financial position, results of operations
and cash flows that would have been reported if the Company had operated as
an unaffiliated enterprise, nor is it indicative of future results.
In connection with the formation of MAP, Marathon acquired certain
refining, marketing and transportation net assets, including the operations
comprising SPLLC, from Ashland in exchange for a 38% interest in MAP. The
acquisition of Ashland's net assets was accounted for under the purchase
method of accounting.
The Company is an independent gatherer and marketer of crude oil in the
United States, operating in 14 states. Major operations consist of
pipeline, barge and truck operations. The pipeline component owns and
operates more than 2,400 miles of active pipelines that transport crude oil
from leases and unloading stations to major pipeline connections and
terminals. The barge facilities consist of eight owned barge terminals
located in Louisiana and Texas. The truck operations consist of a fleet of
more than 250 units transporting crude to various locations.
2. For the quarters ended March 31, 1998 and 1999, the Company was treated as a
partnership for federal and most state income tax purposes, and the tax
effect of its activities accrued to Marathon and Ashland. As a result, no
provision for federal or state income taxes has been made in the
accompanying financial statements.
3. For purposes of these separate financial statements, payables and
receivables related to transactions between the Company and MAP are included
as a component of the Parent Company investment. Transactions during the
first quarter of 1998 and 1999 between the Scurlock Permian Businesses and
Marathon and Ashland are considered to be related party transactions.
4. For the year ended December 31, 1998, the Company recorded a net charge to
costs and expenses of approximately $10 million to reflect an inventory
market valuation reserve. Such amount represented the amount by which the
recorded LIFO cost basis of crude oil inventory exceeded net realizable
value as of such date. At March 31, 1999, the inventory market valuation
reserve was released due to increased crude oil prices and inventory
turnover and the Company recognized a non cash credit to costs and expenses
of approximately $10 million.
F-41
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO INTERIM FINANCIAL STATEMENTS (unaudited)--(Continued)
Inventories consist of the following:
<TABLE>
<CAPTION>
December 31, March 31,
1998 1999
------------ ---------
(Thousands)
<S> <C> <C>
Crude oil............................................. $21,294 $30,349
Pipeline line fill.................................... 4,638 4,400
Materials and supplies................................ 2,004 2,182
Bulk fuel............................................. 336 277
------- -------
Total (at cost)..................................... 28,272 37,208
Less inventory market valuation reserve............... 10,014 --
------- -------
Net inventory carrying value........................ $18,258 $37,208
======= =======
</TABLE>
5. The Company is the subject of, or party to, a number of pending or
threatened legal actions, contingencies and commitments involving a variety
of matters, including laws and regulations relating to the environment.
Under the agreement for the sale of the Company by MAP to Plains, MAP has
agreed to indemnify and hold harmless the Company and Plains for claims,
liabilities and losses (collectively "Losses") resulting from any act or
omission attributable to the Company's business or properties occurring
prior to the date of the closing of such sale to the extent the aggregate
amount of such Losses exceed $1 million; provided however, that claims for
such Losses must be asserted by the Company against MAP on or before May 15,
2003. Certain identified Losses and the first $25,000 of any individual
claim are not included in the calculation of the foregoing $1 million
indemnification threshold.
F-42
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Managers of
Marathon Ashland Petroleum LLC
In our opinion, the accompanying balance sheet and the related statements of
operations, of cash flows and of changes in parent company investment present
fairly, in all material respects, the financial position of the Scurlock
Permian Businesses (a division of Marathon Ashland Petroleum LLC, hereinafter
referred to as MAP) at December 31, 1998, and the results of their operations
and their cash flows for the year then ended, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of MAP'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.
PRICEWATERHOUSECOOPERS LLP
Pittsburgh, Pennsylvania
April 30, 1999
F-43
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Managers of
Marathon Ashland Petroleum LLC
In our opinion, the accompanying balance sheet and the related statements of
operations, of cash flows and of changes in parent company investment present
fairly, in all material respects, the financial position of Scurlock Permian
Corporation, the predecessor entity of the Scurlock Permian Businesses, at
December 31, 1997, and the results of its operations and its cash flows for
each of the two years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of Marathon Ashland Petroleum LLC's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
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
Pittsburgh, Pennsylvania
April 30, 1999
F-44
<PAGE>
SCURLOCK PERMIAN BUSINESSES
STATEMENT OF OPERATIONS
(dollars in thousands)
<TABLE>
<CAPTION>
(Predecessor)
Year Ended
-------------------------
(Company)
December 31, December 31, Year Ended
1996 1997 December 31, 1998
------------ ------------ -----------------
<S> <C> <C> <C>
Revenues--Note E.................................................................. $4,246,245 $4,267,720 $3,773,536
Costs and expenses:
Cost of sales (excludes items shown below)--Note E.............................. 4,189,303 4,214,952 3,742,276
Selling, general and administrative expenses.................................... 32,501 31,800 31,033
Depreciation and amortization................................................... 16,576 16,337 11,136
Taxes other than income taxes................................................... 2,846 2,689 2,653
Inventory market valuation charges (credit)--Note H............................. (2,650) 6,485 10,014
---------- ---------- ----------
Total costs and expenses...................................................... 4,238,576 4,272,263 3,797,112
---------- ---------- ----------
Income (loss) from operations before income taxes................................. 7,669 (4,543) (23,576)
Provision (benefit) for estimated income taxes--Note G............................ 3,148 (1,176) --
---------- ---------- ----------
Net income (loss)................................................................. $ 4,521 $ (3,367) $ (23,576)
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-45
<PAGE>
SCURLOCK PERMIAN BUSINESSES
BALANCE SHEET
(dollars in thousands)
<TABLE>
<CAPTION>
(Predecessor) (Company)
December 31, December 31,
1997 1998
------------- ------------
ASSETS
------
<S> <C> <C>
Current assets:
Cash and cash equivalents......................................................................... $ 34 $ 346
Receivables (net of allowance of $153 and $180)................................................... 262,722 259,368
Inventories--Note H............................................................................... 26,861 18,258
Deferred income taxes--Note G..................................................................... 2,270 --
Other current assets.............................................................................. 3,422 445
-------- --------
Total current assets............................................................................ 295,309 278,417
Investments and long-term receivables--Note I..................................................... 1,614 2,487
Property, plant and equipment--net--Note J........................................................ 109,618 131,815
Other noncurrent assets--net...................................................................... 17,234 1,892
-------- --------
Total assets.................................................................................... $423,775 $414,611
======== ========
<CAPTION>
LIABILITIES
-----------
<S> <C> <C>
Current liabilities:
Accounts payable.................................................................................. $319,111 $294,870
Payroll and benefits payable...................................................................... 5,039 4,865
Other current liabilities......................................................................... 7,621 9,731
-------- --------
Total current liabilities....................................................................... 331,771 309,466
Long-term deferred income taxes--Note G........................................................... 2,473 --
Other long-term liabilities....................................................................... 6,279 --
-------- --------
Total liabilities............................................................................... 340,523 309,466
Parent Company Investment--Note D................................................................... 83,252 105,145
-------- --------
Total liabilities and Parent Company investment................................................. $423,775 $414,611
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-46
<PAGE>
SCURLOCK PERMIAN BUSINESSES
STATEMENT OF CASH FLOWS
(dollars in thousands)
<TABLE>
<CAPTION>
(Predecessor)
Year Ended (Company)
------------------------ Year Ended
December 31, December 31, December 31,
1996 1997 1998
------------ ------------ ------------
<S> <C> <C> <C>
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)...................................................................... $ 4,521 $ (3,367) $(23,576)
Adjustments to reconcile to net cash provided from (used in) operating activities:
Depreciation and amortization........................................................ 16,576 16,337 11,136
Inventory market valuation charges (credits)......................................... (2,650) 6,485 10,014
Deferred income taxes................................................................ 1,657 (2,057) --
Gain on disposal of assets........................................................... 234 18 82
Changes in current assets and liabilities:
Receivables........................................................................ (51,438) 49,190 3,563
Inventories........................................................................ 9,386 4,828 (1,946)
Accounts payable and accrued expenses.............................................. 49,621 (109,103) (10,754)
All other--net....................................................................... 3,064 (1,830) 190
-------- --------- --------
Net cash provided from (used in) operating activities.............................. 30,971 (39,499) (11,291)
-------- --------- --------
Investing activities:
Disposal of assets..................................................................... 1,760 443 117
Capital expenditures................................................................... (5,627) (8,269) (4,293)
Affiliates--distributions from (investments in)........................................ (546) 95 81
-------- --------- --------
Net cash used in investing activities................................................ (4,413) (7,731) (4,095)
-------- --------- --------
Financing Activities:
Net change in Parent Company advances.................................................. (27,017) 46,827 15,698
-------- --------- --------
Net cash provided from (used in) financing activities................................ (27,017) 46,827 15,698
-------- --------- --------
Net increase (decrease) in cash and cash equivalents................................... (459) (403) 312
Cash and cash equivalents at beginning of year......................................... 896 437 34
-------- --------- --------
Cash and cash equivalents at end of year............................................... $ 437 $ 34 $ 346
======== ========= ========
</TABLE>
See Note K for supplemental cash flow information.
The accompanying notes are an integral part of these financial statements.
F-47
<PAGE>
SCURLOCK PERMIAN BUSINESSES
STATEMENT OF CHANGES IN PARENT COMPANY INVESTMENT
(dollars in thousands)
<TABLE>
<CAPTION>
(Predecessor)
-------------
<S> <C>
Parent Company investment at December 31, 1995.................... $62,288
Net income for the year ended December 31, 1996................. 4,521
Net advances from (to) Parent Company........................... (27,017)
-------
Parent Company investment at December 31, 1996.................... 39,792
Net loss for the year ended December 31, 1997................... (3,367)
Net advances from (to) Parent Company........................... 46,827
-------
Parent Company investment at December 31, 1997.................... $83,252
=======
</TABLE>
<TABLE>
<CAPTION>
(Company)
---------
<S> <C>
Parent Company investment at January 1, 1998--Note A................. $113,023
Net loss for the year ended December 31, 1998...................... (23,576)
Net advances from (to) Parent Company.............................. 15,698
--------
Parent Company investment at December 31, 1998....................... $105,145
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-48
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS
NOTE A--BUSINESS DESCRIPTION AND BASIS OF PRESENTATION
Scurlock Permian LLC (SPLLC) is a wholly owned subsidiary of Marathon
Ashland Petroleum LLC (MAP). MAP was formed effective January 1, 1998, and is
owned 62% by Marathon Oil Company (Marathon) and 38% by Ashland Inc. (Ashland).
Prior to January 1, 1998, SPLLC was organized as a stock corporation named
Scurlock Permian Corporation and was a wholly owned subsidiary of Ashland.
Throughout these financial statements, the term, Parent Company, relates to MAP
for 1998 and Ashland for 1996 and 1997.
On March 17, 1999, MAP entered into an agreement with Plains Marketing, L.P.
(Plains) providing for the sale of MAP's membership interest in SPLLC and
certain other pipeline assets (collectively, the Scurlock Permian Businesses or
the Company) to Plains. This transaction is anticipated to be consummated in
the second quarter of 1999. The accompanying financial statements do not
include any adjustments that might result from the proposed sale.
The accompanying financial statements pertain to the business that is being
sold to Plains and represent a carve-out financial statement presentation of a
MAP operating unit as of and for the year ended December 31, 1998, and of
Scurlock Permian Corporation (the Predecessor) as of December 31, 1997 and 1996
and for the years then ended. The financial statements include allocations and
estimates of direct and indirect Parent Company corporate administrative costs
attributable to the Company or the Predecessor as described in Note D. The
methods by which such amounts are attributed or allocated are deemed reasonable
by the Parent Company's management. The financial information herein is not
necessarily indicative of the financial position, results of operations and
cash flows that would have been reported if the Company or the Predecessor had
operated as an unaffiliated enterprise, nor is it indicative of future results.
In connection with the formation of MAP, Marathon acquired certain refining,
marketing and transportation net assets, including the operations comprising
SPLLC, from Ashland in exchange for a 38% interest in MAP. The acquisition of
Ashland's net assets was accounted for under the purchase method of accounting.
As a result, the financial statements of the Scurlock Permian Businesses for
the year ended December 31, 1998, were prepared on a different basis than the
financial statements of the Predecessor for the years ended December 31, 1996
and 1997. Due to this lack of comparability, a "black line" has been used to
separate the reporting periods.
The Company and the Predecessor are independent gatherers and marketers of
crude oil in the United States, operating in 14 states. Major operations
consist of pipeline, barge and truck operations. The pipeline component owns
and operates more than 2,400 miles of active pipelines that transport crude oil
from leases and unloading stations to major pipeline connections and terminals.
The barge facilities consist of eight owned barge terminals located in
Louisiana and Texas. The truck operations consist of a fleet of more than 250
units transporting crude to various locations.
NOTE B--SUMMARY OF PRINCIPAL ACCOUNTING POLICIES
Principles applied in consolidation
The investment in the entity over which the Company or the Predecessor has
significant influence is accounted for using the equity method. The
proportionate share of income from this equity method investment is included in
revenues. The investment in the other entity over which the Company or the
Predecessor does not have significant influence and whose stock does not have a
readily determinable fair value is carried at cost.
Use of estimates
Generally accepted accounting principles require management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at year end
and the reported amounts of revenues and expenses during the year. Significant
items subject to such
F-49
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
estimates and assumptions include the carrying value of long-lived assets,
valuation allowances for receivables and inventories, environmental liabilities
and liabilities for potential claims and settlements. Actual results could
differ from the estimates and assumptions used.
Revenue recognition
Revenues principally include sales, equity income and gains or losses on the
disposal of assets. Sales are recognized when products are shipped or services
are provided to customers. Matching crude oil buy/sell transactions settled in
cash are included in both revenues and costs and expenses, with no effect on
income. As of December 31, 1997 and 1998, receivables from two customers
comprised 12 percent and 11 percent, respectively, of total receivables.
Cash and cash equivalents
Cash and cash equivalents include cash on hand and on deposit. The Company
and the Predecessor participate in the Parent Company's centralized funding and
cash management system (non-interest bearing) (see Note D).
Inventories
Inventories are carried at lower of cost or market. Cost of inventories is
determined primarily under the last-in, first-out (LIFO) method.
Derivative instruments
The Company and the Predecessor engage in commodity risk management
activities within the normal course of its business as an end-user of
derivative instruments (see Note M). Management is authorized to manage
exposure to price fluctuations related to the purchase and sale of crude oil
through the use of derivative non-financial instruments. Derivative non-
financial instruments require or permit settlement by delivery of commodities
and include exchange-traded commodity futures contracts. The Company's and the
Predecessor's practices do not permit derivative positions to remain open if
the underlying physical market risk has been removed. Changes in the market
value of derivative instruments are deferred, including both closed and open
positions, and are subsequently recognized in income, as sales or cost of
sales, in the same period as the underlying transaction. The margin receivable
accounts required for open commodity contracts reflect changes in the market
prices of the underlying commodity and are settled on a daily basis.
Recorded deferred gains or losses are reflected within other current assets
or accounts payable. Cash flows from the use of derivative instruments are
reported in the same category as the hedged item in the Statement of Cash
Flows.
Long-lived assets
Property, plant and equipment are stated at cost and are depreciated
principally by the straight-line method based on estimated useful lives of: a)
15 years for right of way, b) 5 to 15 years for building and furniture, and c)
3 to 15 years for transportation and terminal equipment. Impairment of assets
is evaluated on an individual asset basis or by logical groupings of assets.
Assets deemed to be impaired are written down to their fair value, including
any related goodwill, using discounted future cash flows and, if available,
comparable market values.
F-50
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Environmental liabilities
Provision is made for remediation costs and penalties when the
responsibility to remediate is probable and the amount of associated costs is
reasonably determinable. Generally, the timing of remediation accruals
coincides with completion of a feasibility study or the commitment to a formal
plan of action. Remediation liabilities are accrued based on estimates of known
environmental exposure (see Note N).
Insurance
The Company and the Predecessor maintain insurance for catastrophic casualty
and certain property and business interruption exposures, as well as those
risks required to be insured by law or contract. Costs resulting from
noninsured losses are charged against income upon occurrence.
Income taxes
For the year ended December 31, 1998, the Company was treated as a
partnership for federal and most state income tax purposes, and the tax effect
of its activities accrued to Marathon and Ashland. As a result, no provision
for federal or state income taxes has been made in the accompanying financial
statements for 1998 activity.
Prior to January 1, 1998, when the Predecessor was wholly owned by Ashland,
it operated as a corporation. Accordingly, these financial statements include a
provision for income taxes for the periods ended December 31, 1996 and 1997.
Income taxes pertaining to the years 1996 and 1997 are computed on a separate
return basis using the liability method as prescribed by Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes." Because the
Predecessor was included in the federal and state income tax returns filed by
Ashland, the calculation of the related tax provisions and deferred taxes
necessarily requires certain assumptions, allocations and estimates which
management believes are reasonable to reflect the tax reporting for the
Predecessor as a stand-alone taxpayer.
Fair Value of Financial Instruments
The carrying values of most financial instruments are based on historical
costs. The carrying values of cash and cash equivalents, receivables and
payables approximate their fair value due to the short-term maturity of these
instruments.
NOTE C--NEW ACCOUNTING STANDARD
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS No. 133). This new standard requires recognition
of all derivatives as either assets or liabilities at fair value. SFAS No. 133
may result in additional volatility in both current period earnings and other
comprehensive income as a result of recording recognized and unrecognized gains
and losses resulting from changes in the fair value of derivative instruments.
SFAS 133 requires a comprehensive review of all outstanding derivative
instruments to determine whether or not their use meets the hedge accounting
criteria. It is possible that there will be derivative instruments employed in
the Company's businesses that do not meet all of the designated hedge criteria,
and they will be reflected in income on a mark-to-market basis. Based upon the
strategies currently employed by the Company, the relatively short-term
duration of most of the Company's derivative strategies, and the level of
activity related to commodity-based derivative instruments in recent periods,
the Company does not anticipate the effect of adoption to have a material
impact on either financial position or results of operations. The Company plans
to adopt SFAS No. 133 effective January 1, 2000, as required.
F-51
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
NOTE D--PARENT COMPANY INVESTMENT, ALLOCATIONS AND RELATED PARTY TRANSACTIONS
For purposes of these separate financial statements, payables and
receivables related to transactions between the Company and MAP and the
Predecessor and Ashland, as well as payables and refunds related to income
taxes, are included as a component of the Parent Company investment.
Transactions in 1998 between the Scurlock Permian Businesses and Marathon and
Ashland are considered to be related party transactions.
The Company's sales in 1998 to Ashland were $580 thousand; sales to MAP were
$732,832 thousand; and sales to Marathon were $2,195 thousand. The
Predecessor's sales in 1997 and 1996 to Ashland were $793,920 thousand and
$942,299 thousand, respectively. The Company's purchases in 1998 from MAP
totaled $106,317 thousand and purchases from Marathon were $9,531 thousand. The
Predecessor's purchases in 1997 and 1996 from Ashland totaled $129,816 thousand
and $121,837 thousand, respectively. Such transactions were in the ordinary
course of business and include the purchase, sale and transportation of crude
oil.
MAP, Ashland and Marathon provided computer, treasury, accounting, internal
auditing and legal services to the Company in 1998 and Ashland provided such
services to the Predecessor in 1997 and 1996. Charges for these services were
allocated based on usage or other methods, such as headcount and square
footage, that management believed to be reasonable. Charges to the Company for
these services for the year ended December 31, 1998 totaled $7,722 thousand.
Ashland charges for these services in 1997 and 1996 were $7,787 thousand and
$6,423 thousand, respectively. The Parent Company uses a centralized cash
management system (non-interest bearing) under which cash receipts of the
Company and the Predecessor were remitted to the Parent Company and cash
disbursements of the Company and the Predecessor were funded by the Parent
Company.
As of December 31, 1998, receivables included $832 thousand due from
Ashland. The Company's accounts payable as of December 31, 1998, included
$1,601 thousand due to Marathon.
NOTE E--REVENUES
The items below are included in revenues and costs and expenses, with no
effect on income.
<TABLE>
<CAPTION>
(Predecessor)
Year Ended
-------------------------
(Company)
Year Ended
December 31, December 31, December 31,
1996 1997 1998
------------ ------------ ------------
(Thousands) (Thousands)
<S> <C> <C> <C>
Matching crude oil buy/sell
transactions settled in cash.......... $2,665,054 $2,851,069 $2,179,843
</TABLE>
NOTE F--EMPLOYEE BENEFITS
For the purposes of these financial statements, the Company and the
Predecessor are considered to participate in multi-employer benefit plans.
The Company's employees were included in the various employee benefit plans
of MAP in 1998 and the Predecessor's employees were included in the various
employee benefit plans of Ashland for the years ended December 31, 1997 and
1996. These plans included retirement plans, employee and retiree medical,
dental and life insurance plans, 401(k) and profit-sharing plans and other such
benefits.
MAP has noncontributory defined benefit pension plans covering substantially
all employees of the Scurlock Permian Businesses. Benefits under these plans
are based primarily upon years of service and career earnings. The funding
policy for all plans provides that payments to the pension trusts shall be
equal to the
F-52
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
minimum funding requirements of the Employee Retirement and Income Security
Act, plus such additional amounts as may be approved. No charges have been
allocated to the Scurlock Permian Businesses for the MAP defined benefit
pension plans for the year ended December 31, 1998, as the plans are in an
overfunded position.
MAP also has defined benefit retiree health insurance plans covering most
employees of the Scurlock Permian Businesses upon their retirement. Health
benefits are primarily provided through comprehensive hospital, surgical and
major medical benefit provisions subject to various cost-sharing features.
The Company's and the Predecessor's share of employee benefit expenses were
$4,117 thousand, $4,815 thousand and $3,121 thousand for the years ended
December 31, 1996, 1997 and 1998, respectively.
NOTE G--INCOME TAXES
Provision (benefit) for estimated income taxes:
<TABLE>
<CAPTION>
(Predecessor) Year Ended
-------------------------
December 31, December 31,
1996 1997
------------ ------------
(Thousands) (Thousands)
<S> <C> <C>
Federal taxes:
Current.......................................... $1,389 $ 821
Deferred......................................... 1,657 (2,057)
------ -------
Total federal taxes............................ 3,046 (1,236)
State and local taxes: 102 60
------ -------
Total provision (benefit)........................ $3,148 $(1,176)
====== =======
</TABLE>
For the year ended December 31, 1998, the Company was treated as a
partnership for federal and most state income tax purposes and the tax effect
of its activities accrued to Marathon and Ashland. As a result, no provision
for income taxes has been made in the accompanying financial statements for
1998 activity. Prior to January 1, 1998, the Predecessor was wholly owned by
Ashland and operated as a corporation. Accordingly, these financial statements
include a provision for income taxes for the periods ended December 31, 1996
and 1997. Income taxes pertaining to the years 1996 and 1997 are computed on a
separate return basis using the liability method as prescribed by Statement of
Financial Accounting Standards No. 109.
The deferred tax asset and liability at December 31, 1997 principally arise
from differences between the book and tax basis of inventory and property,
plant and equipment, respectively.
A reconciliation of the federal statutory tax rate (35%) to the total income
tax provision (benefit) follows:
<TABLE>
<CAPTION>
(Predecessor)
-----------------------
1996 1997
----------- -----------
(Thousands) (Thousands)
<S> <C> <C>
Statutory rate applied to income before income
taxes............................................. $2,684 $ (1,590)
Nondeductible goodwill and business expenses....... 398 375
State and local income taxes after federal income
tax benefit....................................... 66 39
------ --------
Total provision (benefit)........................ $3,148 $ (1,176)
====== ========
</TABLE>
F-53
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
NOTE H--INVENTORIES
Inventories consist of the following:
<TABLE>
<CAPTION>
(Predecessor) (Company)
December 31, December 31,
1997 1998
------------- ------------
(Thousands) (Thousands)
<S> <C> <C>
Crude oil........................................................................................ $24,417 $21,294
Pipeline line fill............................................................................... 6,273 4,638
Materials and supplies........................................................................... 2,248 2,004
Bulk fuel........................................................................................ 408 336
------- -------
Total (at cost)................................................................................ 33,346 28,272
Less inventory market valuation reserve.......................................................... 6,485 10,014
------- -------
Net inventory carrying value................................................................... $26,861 $18,258
======= =======
</TABLE>
Inventories of crude oil and pipeline line fill are valued by the LIFO
method. At December 31, 1997 and 1998, the LIFO method accounted for
approximately 92% of the total inventory value. During 1997, inventory
quantities were reduced. This reduction resulted in a liquidation of LIFO
inventory quantities carried at lower costs prevailing in prior years as
compared with the cost of 1997 purchases, the effect of which decreased cost of
goods sold by approximately $1,382 thousand and increased net income by
approximately $898 thousand.
The inventory market valuation reserve reflects the extent that the recorded
LIFO cost basis of crude oil inventories exceeds net realizable value. The
reserve is decreased to reflect increases in market prices and inventory
turnover and increased to reflect decreases in market prices. Changes in the
inventory market valuation reserve result in noncash charges or credits to
costs and expenses.
NOTE I--INVESTMENTS AND LONG-TERM RECEIVABLES
<TABLE>
<CAPTION>
(Predecessor) (Company)
December 31, December 31,
1997 1998
------------- ------------
(Thousands) (Thousands)
<S> <C> <C>
Equity method investment......................................................................... $ 981 $2,466
Cost method investment........................................................................... 633 --
Other............................................................................................ -- 21
------ ------
$1,614 $2,487
====== ======
</TABLE>
F-54
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
The following represents summarized financial information of the affiliate
accounted for by the equity method of accounting:
<TABLE>
<CAPTION>
(Company)
(Predecessor) Year Ended Year Ended
------------------------- ------------
December 31, December 31, December 31,
1996 1997 1998
------------ ------------ ------------
(Thousands) (Thousands)
<S> <C> <C> <C>
Income data:
Revenues............................ $3,039 $2,474 $2,110
Operating income.................... 252 135 66
Net income.......................... 252 135 66
</TABLE>
<TABLE>
<CAPTION>
December 31, December 31,
1997 1998
------------ ------------
(Thousands) (Thousands)
<S> <C> <C>
Balance sheet data:
Current assets................................... $ 28 $ 44
Non-current assets............................... 1,961 1,835
Current liabilities.............................. 28 44
</TABLE>
Dividends and partnership distributions received from equity affiliates in
1996, 1997 and 1998 were $86 thousand, $95 thousand and $81 thousand,
respectively. Purchases from equity affiliates in 1996, 1997 and 1998 totaled
$3,039 thousand, $2,474 thousand and $2,110 thousand, respectively. Sales to
equity affiliates in 1996, 1997 and 1998 totaled $2,233 thousand, $1,825
thousand and $1,552 thousand, respectively.
NOTE J--PROPERTY, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
(Predecessor) (Company)
December 31, December 31,
1997 1998
------------- ------------
(Thousands) (Thousands)
<S> <C> <C>
Land............................................................................................. $ 2,190 $ 1,270
Construction in progress......................................................................... 385 3,025
Right of way..................................................................................... 39,604 17,928
Building and furniture........................................................................... 20,402 3,323
Transportation and terminal equipment............................................................ 210,958 119,890
-------- --------
Total.......................................................................................... 273,539 145,436
Less accumulated depreciation.................................................................... 163,921 13,621
-------- --------
Net............................................................................................ $109,618 $131,815
======== ========
</TABLE>
NOTE K--SUPPLEMENTAL CASH FLOW INFORMATION
<TABLE>
<CAPTION>
(Predecessor)
Year Ended
-------------------------
(Company)
Year Ended
December 31, December 31, December 31,
1996 1997 1998
------------ ------------ ------------
(Thousands) (Thousands)
<S> <C> <C> <C>
Income taxes paid to Parent Company.. $5,836 $5,517 $ --
Non-cash investing and financing
activities:
Like-kind exchanges of
transportation equipment.......... $5,102 $ -- $4,540
</TABLE>
F-55
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
NOTE L--LEASES
The Company and the Predecessor lease a wide variety of facilities and
equipment under operating leases, including land and building space, office
equipment, and transportation equipment.
Future minimum commitments of the Company for operating leases having
remaining, noncancelable lease terms in excess of one year are as follows:
<TABLE>
<CAPTION>
Operating
Leases
-----------
(Thousands)
<S> <C>
1999............................................................. $ 2,073
2000............................................................. 2,071
2001............................................................. 2,073
2002............................................................. 524
2003............................................................. 384
Later Years...................................................... 4,811
-------
Total minimum lease payments................................... $11,936
=======
</TABLE>
Operating lease costs, which consisted principally of minimum rentals, were
$10,922 thousand, $9,430 thousand and $9,396 thousand for the years ended
December 31, 1996, 1997 and 1998, respectively.
NOTE M--DERIVATIVE INSTRUMENTS
The Company and the Predecessor use exchange-traded future contracts to
manage exposure to price fluctuations related to the anticipated purchase and
sale of crude oil. The exchange-traded futures contracts do not have a
corresponding fair value since changes in market prices are settled on a daily
basis. The Company remains at risk for possible changes in the market value of
the derivative instrument; however, such risk should be mitigated by price
changes in the underlying hedged item.
The following table sets forth quantitative information for exchange-traded
commodity futures:
<TABLE>
<CAPTION>
Aggregate
Recorded Contract
Deferred Values
Gain or (Loss) (a)
-------------- ---------
(Thousands)
<S> <C> <C>
(Predecessor)
December 31, 1997:
Exchange-traded commodity futures................. $(2,817) $29,157
(Company)
December 31, 1998:
Exchange-traded commodity futures................. $ 191 $ 8,964
</TABLE>
- --------
(a) Contract or notional amounts do not quantify risk exposure, but are used in
the calculation of cash settlements under the contracts. The contract or
notional amounts do not reflect the extent to which positions may offset
one another.
NOTE N--CONTINGENCIES AND COMMITMENTS
The Company and the Predecessor are the subject of, or party to, a number of
pending or threatened legal actions, contingencies and commitments involving a
variety of matters, including laws and regulations relating to the environment.
Certain of these matters are discussed below. The ultimate resolution of these
contingencies
F-56
<PAGE>
SCURLOCK PERMIAN BUSINESSES
NOTES TO FINANCIAL STATEMENTS--(Continued)
could, individually or in the aggregate, be material to the Company's financial
statements. However, the Company's management believes that the Company will
remain a viable and competitive enterprise even though it is possible that
these contingencies could be resolved unfavorably.
Environmental matters
The Company and the Predecessor are subject to federal, state, and local
laws and regulations relating to the environment. These laws generally provide
for control of pollutants released into the environment and require responsible
parties to undertake remediation of hazardous waste disposal sites. Penalties
may be imposed for noncompliance. At December 31, 1997, the Predecessor had
$4,228 thousand accrued for remediation costs on existing properties. In
connection with the formation of MAP (see Note A), Marathon and Ashland
retained the liability, subject to certain thresholds, for costs associated
with remediating conditions existing prior to January 1, 1998. No amounts were
accrued by the Company at December 31, 1998 for environmental matters. It is
not presently possible to estimate the ultimate amount of all remediation costs
that might be incurred or the penalties that may be imposed.
Commitments
The Company has a contract for use of an oil terminal in Louisiana with an
initial three-year term that began on July 1, 1998. At the end of three years,
the agreement will automatically extend from year to year unless either party
cancels it. The Company is committed to a "minimum receipt throughput volume"
of 4,500 barrels per day at $.25 per barrel.
F-57
<PAGE>
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Directors and Stockholder
of Wingfoot Ventures Seven, Inc.
We have reviewed the accompanying consolidated balance sheets of Wingfoot
Ventures Seven, Inc. as of June 30, 1998, and the related consolidated
statements of income and of cash flows for the six month periods ended June 30,
1998 and 1997. This financial information is the responsibility of the
Company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted
in accordance with generally accepted auditing standards, the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the accompanying consolidated interim financial information
for it to be in conformity with generally accepted accounting principles.
We previously audited in accordance with generally accepted auditing
standards the consolidated balance sheet as of December 31, 1997 and the
related consolidated statements of operations and accumulated deficit, and of
cash flows for the year then ended, and in our report dated July 27, 1998
presented on page F-63 of this Registration Statement we expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated balance sheet
information as of December 31, 1997 is fairly stated in all material respects
in relation to the consolidated balance sheet from which it has been derived.
PRICEWATERHOUSECOOPERS LLP
San Francisco, California
September 23, 1998
F-58
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
<TABLE>
<CAPTION>
December 31, June 30,
1997 1998
------------ -----------
(unaudited)
ASSETS
------
<S> <C> <C>
CURRENT ASSETS
Cash................................................. $ 104 $ 150
Accounts receivable.................................. 64,077 53,367
Receivable from affiliate............................ -- 26,304
Working oil inventory................................ 2,240 5,714
Prepaid expenses and other current assets............ 5,179 6,577
----------- -----------
Total current assets................................. 71,600 92,112
----------- -----------
PROPERTY, PLANT AND EQUIPMENT........................ 1,550,391 1,551,241
Less allowance for depreciation and amortization..... (1,198,683) (1,205,491)
----------- -----------
351,708 345,750
OTHER ASSET
Pipeline linefill.................................... 49,218 49,986
----------- -----------
Total assets......................................... $ 472,526 $ 487,848
=========== ===========
<CAPTION>
LIABILITIES AND STOCKHOLDER'S EQUITY
------------------------------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable..................................... $ 53,065 $ 43,992
Benefits and compensation............................ 1,834 1,459
Accrued expenses..................................... 1,591 1,872
Accrued interest to related party.................... 34,121 --
Accrued taxes........................................ 6,670 7,102
Short-term debt to related party..................... 102,439 --
Other current liabilities............................ 1,071 1,080
----------- -----------
Total current liabilities............................ 200,791 55,505
LONG-TERM LIABILITIES
Long-term debt to related party...................... 705,243 --
Deferred income taxes................................ 7,130 6,830
Benefits and compensation............................ 7,971 7,749
----------- -----------
Total liabilities.................................... 921,135 70,084
----------- -----------
STOCKHOLDER'S EQUITY
Common stock, $100 par value, 1,000 shares
authorized;
issued and outstanding 12 shares.................... 1 1
Additional paid-in capital........................... 907,374 1,773,505
Accumulated deficit.................................. (1,355,984) (1,355,742)
----------- -----------
(448,609) 417,764
----------- -----------
Total liabilities and stockholder's equity........... $ 472,526 $ 487,848
=========== ===========
</TABLE>
See notes to consolidated financial statements.
F-59
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
CONSOLIDATED STATEMENTS OF INCOME
(unaudited) (in thousands)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
-----------------
1997 1998
-------- --------
<S> <C> <C>
REVENUES..................................................... $541,698 $374,654
COST OF SALES AND OPERATIONS................................. 503,085 344,538
-------- --------
Gross margin................................................. 38,613 30,116
EXPENSES
Depreciation and amortization................................ 8,145 6,808
General and administrative................................... 1,603 1,053
-------- --------
Total expenses............................................... 9,748 7,861
-------- --------
Operating income............................................. 28,865 22,255
Related party interest expense............................... 25,112 21,929
-------- --------
Income before income taxes................................... 3,753 326
Provision in lieu of income taxes............................ 572 84
-------- --------
NET INCOME................................................... $ 3,181 $ 242
======== ========
</TABLE>
See notes to consolidated financial statements.
F-60
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited) (in thousands)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
------------------
1997 1998
-------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................ $ 3,181 $ 242
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 8,145 6,808
Deferred income taxes................................... (103) (300)
Changes in assets and liabilities resulting from operating
activities:
Accounts receivable..................................... 5,064 10,710
Receivable from affiliate............................... -- (26,304)
Working oil inventory, prepaid expenses and other
current assets......................................... (15,650) (4,872)
Purchase of pipeline linefill........................... (3,236) (768)
Accounts payable........................................ (5,886) (9,073)
Accrued taxes........................................... 225 432
Accruals and other current liabilities.................. (26,903) (34,206)
Benefits and compensation............................... 40 (222)
-------- --------
Net cash used in operating activities..................... (35,123) (57,553)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures...................................... (1,238) (850)
-------- --------
Net cash used in investing activities..................... (1,238) (850)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from capital contribution........................ -- 866,131
Net proceeds (repayments) of debt to related party........ 35,417 (807,682)
-------- --------
Net cash provided by financing activities................. 35,417 58,449
-------- --------
Net (decrease) increase in cash........................... (944) 46
Cash, beginning of period................................. 1,448 104
-------- --------
Cash, end of period....................................... $ 504 $ 150
======== ========
</TABLE>
See notes to consolidated financial statements.
F-61
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1998
(in thousands)
(unaudited)
1. The Company
Wingfoot Ventures Seven, Inc. ("Wingfoot") is a wholly-owned subsidiary of
The Goodyear Tire & Rubber Company ("Goodyear"). Wingfoot operates in the mid-
stream segment of the energy transportation business and consists of four
operating subsidiaries: All American Pipeline Company ("AAPL") and its wholly-
owned subsidiary, Celeron Gathering Corporation ("CGC"), Celeron Trading and
Transportation ("CT&T") and Celeron Corporation ("CC"). AAPL is engaged in the
operation of a heated crude oil pipeline which extends approximately 1,233
miles from Las Flores and Gaviota on the California coast to West Texas. As a
common carrier, AAPL charges transportation tariffs which must be filed with
the Federal Energy Regulatory Commission ("FERC") and the Public Utilities
Commission of the State of California ("CPUC"). CGC operates a proprietary
crude oil gathering pipeline in the San Joaquin Valley area of California. CT&T
is engaged in purchasing, selling and exchanging crude oil, a substantial
portion of which is transported through AAPL's pipeline. CC provides management
services to AAPL, CGC and CT&T.
On March 21, 1998, a Stock Purchase Agreement ("the Agreement") was executed
between Wingfoot and Plains All American Inc. ("PAAI"), a wholly-owned
subsidiary of Plains Resources Inc., whereby all of the issued and outstanding
shares of the capital stock of AAPL and CT&T would be sold to PAAI contingent
upon, among other things, approval by the Federal Trade Commission and the
CPUC. The net assets to be sold are comprised of assets and liabilities of
AAPL, CGC and CT&T and include or exclude all assets and liabilities listed in
certain Bills of Sale and Assumption Agreements included in the Agreement. In
addition, the following items have been excluded from the net assets to be
sold: all of Wingfoot's intercompany transactions with Goodyear; certain other
liabilities; and debt and interest owed to Goodyear and its subsidiaries. On
July 30, 1998, the Agreement was consummated by PAAI for approximately $400
million, including transaction costs.
2. Accounting Policies
The accompanying unaudited consolidated financial statements have been
prepared in accordance with the instructions of interim financial reporting as
prescribed by the Securities and Exchange Commission. All material adjustments
consisting only of normal recurring adjustments which, in the opinion of
management, were necessary for a fair statement of the results for the interim
periods, have been reflected. These consolidated unaudited interim financial
statements should be read in conjunction with the annual consolidated financial
statements of Wingfoot included elsewhere in this Prospectus.
3. Related Party Debt
Pursuant to the Agreement, Wingfoot is obligated to repay the outstanding
related party debt and accrued interest of certain of its subsidiaries prior to
closing. On June 15, 1998, Goodyear made capital contributions of $866,131 and
cash payments of $15,494 for repayments to Wingfoot. Upon receipt of the
$881,625, Wingfoot paid Goodyear $865,219 ($843,269 for repayment of certain
outstanding related party debt and accrued interest at December 31, 1997 and
$21,950 for repayment of related party accrued interest from January 1, 1998 to
May 29, 1998) and remitted the remaining $16,406 to Goodyear for payment of
certain other liabilities to be assumed by Goodyear as a result of the
Agreement.
4. Subsequent Event
Pursuant to the Agreement, in July 1998, an affiliate of Goodyear repaid
$26.3 million to Wingfoot. Concurrently, Wingfoot distributed $25.1 million to
Goodyear.
F-62
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of
Wingfoot Ventures Seven, Inc. (a wholly-owned subsidiary of
The Goodyear Tire and Rubber Company)
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations and accumulated deficit and of cash flows
present fairly, in all material respects, the financial position of Wingfoot
Ventures Seven, Inc. (a wholly-owned subsidiary of The Goodyear Tire & Rubber
Company) and its subsidiaries at December 31, 1996 and 1997, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with 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
San Francisco, California
July 27, 1998
F-63
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
<TABLE>
<CAPTION>
December 31,
------------------------
1996 1997
----------- -----------
ASSETS
------
<S> <C> <C>
Cash................................................. $ 1,448 $ 104
Accounts receivable.................................. 66,433 64,077
Working oil inventory................................ 5,789 2,240
Prepaid expenses and other current assets............ 4,862 5,179
----------- -----------
Total current assets............................. 78,532 71,600
----------- -----------
Property, plant and equipment (Note 3)............... 1,549,178 1,550,391
Less--accumulated depreciation....................... (1,128,556) (1,198,683)
----------- -----------
420,622 351,708
Pipeline linefill.................................... 9,826 49,218
----------- -----------
Total assets..................................... $ 508,980 $ 472,526
=========== ===========
<CAPTION>
LIABILITIES AND STOCKHOLDER'S EQUITY
------------------------------------
<S> <C> <C>
Accounts payable..................................... $ 67,097 $ 53,065
Benefits and compensation............................ 1,465 1,834
Accrued expenses..................................... 4,804 1,591
Accrued interest to related party (Note 4)........... 30,282 34,121
Accrued taxes........................................ 8,594 6,670
Short-term debt to related party (Note 4)............ 56,581 102,439
Other current liabilities............................ 368 1,071
----------- -----------
Total current liabilities........................ 169,191 200,791
Long-term debt to related party (Note 4)............. 705,243 705,243
Deferred income taxes................................ 7,833 7,130
Benefits and compensation............................ 8,237 7,971
----------- -----------
Total liabilities................................ 890,504 921,135
----------- -----------
Commitments and contingencies (Note 12)
Stockholder's equity:
Common stock, $100 par value--authorized 1,000
shares; issued and outstanding 12 shares.......... 1 1
Additional paid-in capital......................... 907,374 907,374
Accumulated deficit................................ (1,288,899) (1,355,984)
----------- -----------
Total equity..................................... (381,524) (448,609)
----------- -----------
Total liabilities and stockholders' equity......... $ 508,980 $ 472,526
=========== ===========
</TABLE>
The accompanying notes are an integral part of this statement.
F-64
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
(dollars in thousands)
<TABLE>
<CAPTION>
For the Years Ended December 31,
-----------------------------------
1995 1996 1997
--------- ----------- -----------
<S> <C> <C> <C>
Revenues (Note 11)........................ $ 619,277 $ 929,299 $ 992,318
--------- ----------- -----------
Expenses:
Purchases, transportation, and storage.. 482,130 791,729 892,618
Property taxes.......................... 7,100 8,500 7,450
Operations and maintenance.............. 28,573 25,812 23,084
Depreciation and amortization........... 39,276 42,760 16,290
Impairment of pipeline assets and
linefill (Note 3)...................... -- 851,878 64,173
Loss on sale of pipeline assets......... 5,000 -- --
Related party interest expense (Note
4)..................................... 50,869 49,000 52,745
General and administrative.............. 4,834 2,961 2,767
--------- ----------- -----------
Total expenses........................ 617,782 1,772,640 1,059,127
--------- ----------- -----------
(Loss) income before income taxes......... 1,495 (843,341) (66,809)
Charge/(benefit) in lieu of income taxes.. (324) 4,227 276
--------- ----------- -----------
Net income (loss)......................... 1,819 (847,568) (67,085)
Beginning accumulated deficit............. (443,150) (441,331) (1,288,899)
--------- ----------- -----------
Ending accumulated deficit................ $(441,331) $(1,288,899) $(1,355,984)
========= =========== ===========
</TABLE>
The accompanying notes are an integral part of this statement.
F-65
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
<TABLE>
<CAPTION>
For the Years Ended
December 31,
-----------------------------
1995 1996 1997
-------- --------- --------
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss)............................. $ 1,819 $(847,568) $(67,085)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation and amortization............... 39,276 42,760 16,290
Impairment of pipeline assets and linefill.. -- 851,878 64,173
Loss on sale of pipeline assets............. 5,000 -- --
Deferred income taxes....................... 2,341 (933) (703)
Changes in assets and liabilities resulting
from operating activities:
Accounts receivable......................... (982) (28,183) 2,356
Working oil inventory....................... (971) 305 3,549
Prepaid expenses and other current assets... (855) (218) (317)
(Purchase) sale of pipeline linefill........ 31,187 (2,870) (49,727)
Accounts payable............................ 2,898 41,316 (14,032)
Benefits and compensation................... (2,580) -- 103
Accrued expenses............................ 526 (1,596) (3,213)
Accrued interest to related party........... 4,841 (3,906) 3,839
Accrued taxes............................... (1,051) 4,149 (1,924)
Other current liabilities................... (31) 368 703
-------- --------- --------
Net cash provided by (used in) operating
activities................................. 81,418 55,502 (45,988)
-------- --------- --------
Cash flows from investing activities:
Capital expenditures.......................... (4,319) (3,983) (2,463)
Proceeds from sale of pipeline assets......... 1,998 125 1,249
-------- --------- --------
Net cash used in investing activities....... (2,321) (3,858) (1,214)
-------- --------- --------
Cash flows from financing activities:
Net (repayments) proceeds of debt to related
party (Note 4)............................... (84,060) (51,024) 45,858
-------- --------- --------
Net cash (used in) provided by financing
activities................................. (84,060) (51,024) 45,858
-------- --------- --------
Net (decrease) increase in cash................. (4,963) 620 (1,344)
Cash, beginning of the year..................... 5,791 828 1,448
-------- --------- --------
Cash, end of the year........................... $ 828 $ 1,448 $ 104
======== ========= ========
</TABLE>
The accompanying notes are an integral part of this statement.
F-66
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1996 AND 1997
(dollars in thousands)
1. The Company
Wingfoot Ventures Seven, Inc. ("Wingfoot") is a wholly-owned subsidiary of
The Goodyear Tire & Rubber Company ("Goodyear or the Parent"). The Company
operates in the mid-stream segment of the energy transportation business and
consists of four operating subsidiaries; All American Pipeline Company ("AAPL")
and its wholly-owned subsidiary, Celeron Gathering Corporation ("CGC"), Celeron
Trading and Transportation ("CT&T") and Celeron Corporation ("CC"). AAPL is
engaged in the operation of a heated crude oil pipeline which extends
approximately 1,233 miles from Las Flores and Gaviota on the California coast
to West Texas. As a common carrier, AAPL charges transportation tariffs which
must be filed with the Federal Energy Regulatory Commission ("FERC") and the
Public Utilities Commission of the State of California ("CPUC"). CGC operates a
proprietary crude oil gathering pipeline in the San Joaquin Valley area of
California. CT&T is engaged in purchasing, selling and exchanging crude oil, a
substantial portion of which is transported through AAPL's pipeline. CC
provides management services to AAPL, CGC and CT&T.
On March 21, 1998, a Stock Purchase Agreement ("the Agreement") was executed
between Wingfoot and Plains All American Inc. ("PAAI"), a wholly-owned
subsidiary of Plains Resources Inc., whereby all of the issued and outstanding
shares of the capital stock of AAPL and CT&T would be sold to PAAI contingent
upon, among other things, approval by the Federal Trade Commission and the
CPUC. The net assets to be sold are comprised of assets and liabilities of
AAPL, CGC and CT&T and include or exclude all assets and liabilities listed in
certain Bills of Sale and Assumption Agreements included in the Agreement. In
addition, the following items have been excluded from the net assets to be
sold: all of Wingfoot's intercompany transactions with Goodyear; certain other
liabilities; and debt and interest owed to Goodyear and its subsidiaries.
2. Summary of Significant Accounting Policies
Basis of consolidation
The consolidated financial statements include the accounts of Wingfoot and
its wholly-owned 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 amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Concentration of credit risk and major customers
Financial instruments which potentially expose Wingfoot to concentrations of
credit risk consist primarily of accounts receivable. Wingfoot's accounts
receivable are primarily from major oil companies and their affiliates, as well
as independent oil companies. Wingfoot generally requires its smaller
independent customers to provide letters of credit. Although Wingfoot is
directly affected by the financial well being of the oil and gas industry,
management does not believe significant credit risk exists. Historically,
credit losses have not been significant.
F-67
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
Revenue recognition
As a regulated interstate pipeline, AAPL recognizes revenues for the
transportation of crude oil based upon FERC and CPUC filed tariff rates and the
related transported volume. AAPL recognizes tariff revenue at the time such
volume is delivered. CT&T and CGC recognize revenue from the sale of crude oil
to third parties at the time title to the product sold transfers to the
purchaser.
Statement of cash flows
There was no cash used to pay income taxes during the years ended December
31, 1995, 1996 and 1997. Interest of $46,028, $52,906 and $48,906 was paid for
the years ended December 31, 1995, 1996 and 1997, respectively.
Working oil inventory
Working oil inventory is carried at the lower of current market value or
cost and determined under the last-in, first-out method.
Property, plant and equipment and pipeline linefill
Property, plant and equipment (the "System") consists primarily of oil
pipeline facilities, which include the cost of land, rights-of-way, pipe, pump
station equipment, storage tanks, vehicles, material, labor, overhead and
interest incurred during the construction period. Depreciation on oil pipeline
facilities is computed using the straight-line method, principally over 37
years (see Note 3). Repairs and maintenance costs are charged to expense as
incurred.
Pipeline linefill consists of crude oil linefill used to pack a pipeline
such that when an incremental barrel enters a pipeline it forces a barrel out
at another location. Proceeds from the sale and repurchase of pipeline linefill
are reflected as cash flows from operating activities in the accompanying
consolidated statements of cash flows.
The System and pipeline linefill are assessed for possible impairment in
accordance with the provisions of Statement of Financial Accounting Standards
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" (SFAS 121). Under this standard, the occurrence of
certain events may trigger a review of affected assets for possible impairment.
An impairment is deemed to exist if the sum of undiscounted before-tax expected
future cash flows for the asset are less than the asset's carrying value. If an
impairment is indicated, the amount of the impairment is measured as the
difference between the asset's fair market value and its carrying value. Where
a market value is not available, it is approximated by Wingfoot's best estimate
of the sum of discounted before-tax expected future cash flows. Impairment
amounts are recorded as impairment of pipeline assets and linefill in the
period in which a specific event occurs (see Note 3).
Income taxes
Wingfoot and its subsidiaries' results are included in the consolidated
federal income tax return of its parent, Goodyear. Tax losses and investment
tax credits have been generated by AAPL and have been utilized in the
consolidated federal income tax returns of Goodyear. In accordance with AAPL's
tax sharing agreement with Goodyear, the tax benefits from the cumulative tax
losses and investment tax credits are not payable by
F-68
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
Goodyear to AAPL until such time as these credits can be utilized on the basis
of a separate company tax computation. While Goodyear has realized tax benefits
from losses and tax credits of AAPL in its consolidated return, AAPL will not
receive reimbursement until a tax liability is incurred as calculated on a
separate company basis. To the extent that future taxable income is generated,
AAPL has a potential future net reimbursement from Goodyear for the benefit of
prior years' tax losses and investment tax credits generated in the amount of
approximately $573,000 and $569,000 at December 31, 1996 and 1997,
respectively. Utilizing the stand-alone calculation required by the tax sharing
agreement, this potential reimbursement results in a net deferred tax asset on
AAPL's balance sheet. Following the terms of the tax sharing agreement, the net
asset has been fully offset by a valuation allowance.
In connection with the Agreement, PAAI and Goodyear will execute an IRS
Section 338(h)(10) election that provides for a step-up in basis of the
acquired assets, which will eliminate any deferred tax liability at the
acquisition date. In addition, any future net reimbursement from Goodyear for
the benefit of prior years' tax losses and investment tax credits will be
extinguished.
Wingfoot's provision for income taxes includes federal and state taxes
currently payable and deferred taxes arising from temporary differences.
Financial instruments
Wingfoot utilizes New York Mercantile Exchange crude oil futures contracts
to manage its exposure to price volatility for its crude trading activities.
Specifically, Wingfoot enters into these contracts to hedge its firm
commitments and anticipated transactions. All contracts permit settlement by
physical delivery of crude oil. Gains and losses related to these contracts are
deferred and recorded when the underlying hedged transaction occurs.
3. Property, Plant and Equipment
The System consists of the following:
<TABLE>
<CAPTION>
December 31,
------------------------
1996 1997
----------- -----------
<S> <C> <C>
Oil pipeline facilities......................... $ 1,549,178 $ 1,550,391
Less: accumulated depreciation.................. (1,128,556) (1,198,683)
----------- -----------
$ 420,622 $ 351,708
=========== ===========
</TABLE>
During 1996, industry developments occurred indicating that the quantities
of California and Alaska North Slope crude oil expected to be tendered in the
future to the System for transportation would be below prior estimates and that
volumes of crude oil expected to be tendered to the System for transportation
to markets outside of California in the future would be significantly lower
than previously anticipated. As a result, management determined that the future
cash flows expected to be generated by the System and pipeline linefill would
be less than their carrying value. In accordance with SFAS 121, Wingfoot
reduced the carrying value of the System and pipeline linefill to their fair
value at December 31, 1996, and recorded a charge of $851,878.
As a result of the Agreement, Wingfoot reviewed the System and pipeline
linefill, which was held for use at December 31, 1997, for impairment since it
was more likely than not that a sale would occur significantly before the end
of its previously estimated remaining useful life. Management determined that
the undiscounted before-tax future cash flows expected to be generated by the
System and pipeline linefill would be less than
F-69
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
their carrying value. In accordance with SFAS 121, Wingfoot reduced the
carrying value of the System and pipeline linefill to their fair value at
December 31, 1997, determined using discounted before-tax expected future cash
flows from the System and pipeline linefill, and recorded a charge of $64,173.
4. Debt
Line of credit
At December 31, 1996 and 1997 to satisfy margin requirements associated with
its futures contracts, Wingfoot had a short-term uncommitted credit arrangement
totaling $1,500 and $3,000, respectively, of which $1,162 and $2,973,
respectively, was unused. This arrangement bears interest at London Interbank
Offered Rate (LIBOR) plus 0.75%. There are no commitment fees or compensating
balances associated with this arrangement.
Short-term debt to related party
Short-term debt at December 31, 1996 and 1997 represents advances from
Goodyear and its subsidiaries. These advances do not accrue interest and are
payable on demand (see Note 13).
Long-term debt to related party
On April 25, 1994, Wingfoot entered into a term loan with Goodyear and its
subsidiaries under which Wingfoot may borrow up to $825,000. The loan bears
interest annually, at a variable rate, generally tied to LIBOR and other
factors relating to the borrowing capacity of Goodyear and its subsidiaries.
<TABLE>
<CAPTION>
December 31,
-----------------
1996 1997
-------- --------
<S> <C> <C>
Term loan due to an affiliate, interest at 12-month LIBOR
plus 1 1/2%, 6.72% and 7.52% at December 31, 1996 and
1997, respectively....................................... $705,243 $705,243
Less amount due in one year............................... -- --
-------- --------
$705,243 $705,243
======== ========
</TABLE>
At December 31, 1996 and 1997, Wingfoot had an outstanding balance of
$705,243 under this loan. Wingfoot is required to make annual mandatory
principal repayments of $100,000 beginning April 30, 1999, $100,000 in 2000,
$125,000 in 2001, $150,000 in 2002, $150,000 in 2003 and $80,243 in 2004.
Interest costs incurred through the term loan totaled $50,869, $49,000 and
$52,745 for the years ended December 31, 1995, 1996, and 1997, respectively.
Substantially all amounts outstanding were repaid subsequent to December 31,
1997 (see Note 13).
Credit agreement
On April 25, 1994, Wingfoot entered into a credit agreement with an
affiliate under which Wingfoot may borrow up to $250,000. The agreement
provides for a .10% per annum commitment fee on the daily average unused amount
of the facility. The loan bears interest at a variable rate based on LIBOR.
There is no balance outstanding at December 31, 1996 and 1997.
5. Financial Instruments
The carrying values of Wingfoot's accounts receivable, other current assets,
accounts payable, accrued expenses, and other current liabilities approximate
fair value due to the short-term maturities of these assets and liabilities.
The carrying value of Wingfoot's line of credit approximates fair value as
interest rates are variable,
F-70
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
based upon prevailing rates for similar agreements. Deferred gains associated
with Wingfoot's futures contracts at December 31, 1996 and 1997 totaled $13 and
$1,071, respectively.
6. Book Overdrafts
At December 31, 1996 and 1997, Wingfoot had $3,281 and $626, respectively,
in book overdrafts representing outstanding checks in excess of funds on
deposit. These amounts have been included in accounts payable.
7. Applicability of Statement of Financial Accounting Standards (SFAS No. 71)
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation,"
provides guidance in preparing financial statements for entities with
operations subject to rate-making authorities. The tariff rates of Wingfoot's
pipeline are regulated by the FERC and the CPUC.
Prior to commencement of operations in 1989, as allowed by FERC, Wingfoot
had capitalized an Allowance for Funds Used During Construction (AFUDC) for
rate-making purposes. The recording of any AFUDC represents the implicit cost
of financing construction as if the construction was financed through a
combination of borrowings and equity contributions. SFAS No. 71 requires that
an AFUDC recorded for rate-making purposes should be recorded for financial
reporting purposes as well, as long as there is reasonable assurance that costs
incurred will be recoverable in the future.
At year end 1996, Wingfoot did not expect to recover the costs that had been
previously capitalized. Accordingly, Wingfoot has discontinued the application
of SFAS No. 71 and in December 1996 adopted the provisions of SFAS No. 101,
"Regulated Enterprise Accounting for the Discontinuation of Application of FASB
Statement No. 71." This statement requires Wingfoot to eliminate the effects of
any actions of regulators that had been recognized as an asset that would not
have normally been recognized by a non-regulated entity. As the only cost
capitalized under the provisions of SFAS No. 71 was AFUDC, no additional
impairment was recorded as the AFUDC balance was included in the FAS No. 121
impairment writedown (see Note 3).
8. Related Party Transactions
During 1996, Wingfoot transferred long-term credits of $30,843 to Goodyear,
increasing Wingfoot's long-term debt payable to Goodyear. Wingfoot has no
further benefit or obligation related to these matters.
Wingfoot's related party financing arrangements are described in Note 4.
Affiliated companies provide personnel and support services to Wingfoot. For
the years ended December 31, 1995, 1996 and 1997, Wingfoot incurred
approximately $400, $361 and $477, respectively, for such services.
Goodyear has guaranteed Wingfoot's obligations with various counter parties
in connection with crude purchase agreements and crude exchanges made in the
ordinary course of business (see Note 12).
F-71
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
9. Employee Benefit Plans
Postretirement health care benefits
Wingfoot provides its associates with health care benefits upon retirement.
The healthcare benefits are provided by insurance companies through premiums
based on expected benefits to be paid during the year. Portions of the
healthcare benefits are not insured and are paid by the plan.
The net periodic postretirement benefit cost:
<TABLE>
<CAPTION>
For the Year
Ended December
31,
----------------
1995 1996 1997
---- ---- ----
<S> <C> <C> <C>
Service cost............................................ $ 63 $ 71 $ 86
Interest cost........................................... 185 183 186
Net amortization........................................ (23) (9) (10)
---- ---- ----
Net periodic postretirement benefit cost................ $225 $245 $262
==== ==== ====
</TABLE>
The following table sets forth the funded status and amounts recognized on
Wingfoot's Consolidated Balance Sheet:
<TABLE>
<CAPTION>
December 31,
----------------
1996 1997
------- -------
<S> <C> <C>
Actuarial present value of accumulated benefit obligation:
Retirees.................................................. $(1,838) $(1,759)
Vested active plan participants........................... (116) (194)
Other active plan participants............................ (480) (566)
------- -------
Accumulated benefit obligation in excess of plan assets..... (2,434) (2,519)
Unrecognized net (gain)..................................... (409) (243)
------- -------
Accrued postretirement benefit cost recognized on the
Consolidated Balance Sheet................................. $(2,843) $(2,762)
======= =======
</TABLE>
<TABLE>
<CAPTION>
1995 1996 1997
---- ---- ----
<S> <C> <C> <C>
The assumptions used were:
Discount rate......................................... 7.75% 7.75% 7.75%
Rate of increase in compensation levels............... 4.50 4.50 4.50
</TABLE>
An 8.00% annual rate of increase in the cost of health care benefits for
retirees under 65 years of age and a 5.75% annual rate of increase for retirees
65 years or older are assumed in 1998. This rate gradually decreases to 5.00%
in 2010 and remains at that level thereafter. To illustrate the significance of
a 1.00% increase in the assumed healthcare cost trend, the accumulated benefit
obligation would increase by $30 at December 31, 1997 and the aggregate service
and interest cost by $3 for the year then ended.
The Agreement specifies that postretirement healthcare benefit obligations
for only non-vested employees will be assumed by PAAI. PAAI does not intend to
continue such benefits subsequent to the acquisition. After the close of the
sale, postretirement healthcare benefits for retirees and vested employees will
be funded by Goodyear.
F-72
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
Pension plan
Substantially all of Wingfoot's associates participate in the pension plan
of CC. CC makes contributions to the pension plan equal to the amount accrued
for pension costs.
Net periodic pension (credit) follows:
<TABLE>
<CAPTION>
For the Year Ended
December 31,
-----------------------
1995 1996 1997
----- ------- -------
<S> <C> <C> <C>
Service cost.................................... $ 305 $ 315 $ 340
Interest cost................................... 544 578 616
Expected return on plan assets.................. (990) (1,292) (1,536)
Amortization.................................... (187) (222) (323)
----- ------- -------
Net periodic pension (credit)................... $(328) $ (621) $ (903)
===== ======= =======
</TABLE>
The following table sets forth the funded status and amounts recognized on
Wingfoot's Consolidated Balance Sheet dated December 31, 1996 and 1997. At the
end of 1996 and 1997, assets exceeded accumulated benefits. Plan assets are
invested primarily in common stocks and fixed income securities.
<TABLE>
<CAPTION>
December 31,
----------------
1996 1997
------- -------
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation............................. $(5,380) $(5,625)
------- -------
Accumulated benefit obligation........................ (6,796) (7,434)
------- -------
Projected benefit obligation.......................... (8,115) (9,073)
Plan assets........................................... 17,234 21,446
------- -------
Projected benefit obligation less than plan assets.... 9,119 12,373
Unrecognized net gain................................. (3,775) (6,313)
Unrecognized prior service cost....................... (55) (51)
Unrecognized net (assets) at transition............... (1,238) (1,054)
Adjustment required to recognize minimum liability.... -- --
------- -------
Pension asset recognized on the Consolidated Balance
Sheet................................................ $ 4,051 $ 4,955
======= =======
</TABLE>
In connection with the sale, CC has amended the Pension Plan document to
provide for an election to participants to request a lump-sum or annuity
distribution of vested benefits, for a six-month period after July 31, 1998,
the expected consummation date of the sale of Wingfoot. Further, on July 31,
1998, the accrued benefits under the Plan will be frozen and will become the
responsibility of Goodyear. This amendment has been approved by CC's Board of
Directors.
F-73
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
Management plans
AAPL and CC have two non-qualified, unfunded plans that cover certain past
management and designated current management. The net periodic pension cost for
these plans consisted of:
<TABLE>
<CAPTION>
For the Year End
December 31,
-------------------
1995 1996 1997
----- ----- -----
<S> <C> <C> <C>
Interest cost........................................ $ 416 $ 409 $ 375
Amortization of gain................................. (28) (2) (11)
----- ----- -----
Net periodic pension cost............................ $ 388 $ 407 $ 364
===== ===== =====
</TABLE>
The funded status of these plans consisted of:
<TABLE>
<CAPTION>
December 31,
----------------
1996 1997
------- -------
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation............................. $(3,122) $(2,822)
------- -------
Accumulated benefit obligation........................ (3,122) (2,822)
------- -------
Projected benefit obligation.......................... (5,164) (4,838)
Plan assets........................................... -- --
------- -------
Projected benefit obligation less than plan assets.... (5,164) (4,838)
Unrecognized net gain................................. (332) (369)
Adjustment required to recognize minimum liability.... (42) --
------- -------
Pension liability recognized on the Consolidated
Balance Sheet........................................ $(5,538) $(5,207)
======= =======
</TABLE>
Under the Agreement, the liability associated with the management plans will
not be transferred to PAAI. The vested benefits under the management plans will
be paid by Goodyear.
Significant assumptions used in the calculation of pension expense and
obligations for the pension and management plans were:
<TABLE>
<CAPTION>
1995 1996 1997
----- ----- -----
<S> <C> <C> <C>
Discount rate.......................................... 7.75% 7.75% 7.50%
Rate of increase in compensation levels................ 5.00% 5.00% 5.00%
Expected long-term rate of return on plan assets....... 9.00% 9.00% 9.00%
</TABLE>
Employee savings plan
Substantially all of Wingfoot's associates are eligible to participate in a
savings plan administered by Goodyear. Under this plan associates elect to
contribute a percentage of their pay. In 1995, 1996 and 1997, the plan provided
for Wingfoot's matching of these contributions (up to a maximum of 6.00% of the
associate's annual pay or, if less, $9,500) at a rate of 50.00%. Wingfoot's
contributions were $251, $229 and $172 for the years ended December 31, 1995,
1996 and 1997, respectively. In connection with the sale, Wingfoot's associates
can no longer contribute to the savings plan after the closing. All vested
Wingfoot contributions will be funded by Goodyear.
F-74
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
10. Income Taxes
Wingfoot's effective income tax rate varied from the statutory U.S. federal
income tax rate of 35% due to state taxes and the valuation allowance recorded
to offset net deferred tax assets.
Deferred tax liabilities at December 31, 1996 and 1997 result primarily from
temporary differences between book and tax treatments of depreciation, and
capitalized construction costs, including interest. Deferred tax assets at
December 31, 1996 and 1997 result primarily from AAPL's prior year tax losses
and investment tax credits. The resulting deferred tax assets have been fully
offset by a valuation allowance of $202,000 and $488,000 at December 31, 1996
and 1997, respectively.
Wingfoot records its deferred taxes on a tax jurisdiction basis and
classifies the net deferred tax amounts as current or non-current based on the
balance sheet classifications of the related assets or liabilities. Based on
this methodology, Wingfoot has recorded its net deferred tax liability as long-
term.
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
December 31,
----------------------
1995 1996 1997
------- ------ -----
<S> <C> <C> <C>
Federal:
Current......................................... $(3,505) $4,320 $ 139
Deferred........................................ 2,341 (933) (703)
State:
Current......................................... 840 840 840
------- ------ -----
Charge/(benefit) in lieu of income taxes.......... $ (324) $4,227 $ 276
======= ====== =====
</TABLE>
In connection with the Agreement, PAAI and Goodyear will execute an IRS
Section 338(h)(10) election (see Note 2).
11. Revenues Attributable to Major Customers
During 1995, sales to three companies accounted for 64% (32% to Company B,
18% to Company A and 14% to Company D) of Wingfoot's total revenues. During
1996, sales to two companies accounted for 38% (21% to Company B and 17% to
Company A) of Wingfoot's total revenues. Sales to three companies accounted for
46% (18% to Company A, 15% to Company B and 13% to Company C) of Wingfoot's
total revenue during 1997. No other single customer accounted for as much as
10% of total sales during 1995, 1996 or 1997.
F-75
<PAGE>
WINGFOOT VENTURES SEVEN, INC.
(A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
DECEMBER 31, 1995, 1996 AND 1997
12. Commitments and Contingencies
Wingfoot leases office space under leases accounted for as operating leases.
Rental expense amounted to $1,605, $1,195 and $981 for the years ended December
31, 1995, 1996 and 1997, respectively. Minimum rental payments under operating
leases are as follows:
<TABLE>
<CAPTION>
Operating
Year Ending December 31, Leases
------------------------ ---------
<S> <C>
1998.......................................................... $ 924
1999.......................................................... 893
2000.......................................................... 878
2001.......................................................... 874
2002.......................................................... 875
Thereafter.................................................... 3,273
------
$7,717
======
</TABLE>
Wingfoot incurred costs associated with leased land, rights-of-way, permits
and regulatory fees of $701, $590 and $479 for the years ended December 31,
1995, 1996 and 1997, respectively. At December 31, 1997, minimum future
payments, net of sublease income, associated with these contracts are
approximately $476 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 connection with its crude oil marketing, Goodyear provides certain
parties with Parent Guaranties to secure Wingfoot's obligation for the purchase
of crude oil. Generally, these Guaranties are issued from one year to unlimited
periods. At December 31, 1997, Wingfoot had outstanding letters of credit of
approximately $2,860. Such letters of credit are secured by the crude inventory
and accounts receivable of Wingfoot and are guaranteed by Goodyear.
In order to receive electrical power service at certain remote locations,
Wingfoot 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, 1997 are approximately $760 annually for each of the
next five years.
At December 31, 1997, Wingfoot was not a subject of any significant
litigation, loss contingencies or other claims. Under the terms of the
Agreement, Wingfoot has agreed in certain circumstances to indemnify PAAI,
above a minimum aggregate amount and subject to a limitation, as defined in the
Agreement, for losses arising from future litigation, loss contingencies and
claims relating to events that occurred prior to the closing date.
13. Subsequent Events
Pursuant to the Agreement, Wingfoot is obligated to repay the outstanding
related party debt and accrued interest of certain of its subsidiaries prior to
closing. On June 15, 1998, Goodyear made capital contributions of $866,131 and
cash payments of $15,494 for repayments to Wingfoot. Upon receipt of the
$881,625, Wingfoot paid Goodyear $865,219 ($843,269 for repayment of certain
outstanding related party debt and accrued interest at December 31, 1997 and
$21,950 for repayment of related party accrued interest from January 1, 1998 to
May 29, 1998) and remitted the remaining $16,406 to Goodyear for payment of
certain other liabilities to be assumed by Goodyear as a result of the
Agreement.
F-76
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholder of Plains All American Inc.
In our opinion, the accompanying consolidated balance sheet presents fairly,
in all material respects, the financial position of Plains All American Inc. (a
wholly owned subsidiary of Plains Resources Inc.) at December 31, 1998 in
conformity with generally accepted accounting principles. This consolidated
balance sheet is the responsibility of Plains All American Inc.'s management;
our responsibility is to express an opinion on this consolidated balance sheet
based upon our audit. We conducted our audit of this consolidated balance sheet
in accordance with generally accepted auditing standards which require that we
plan and perform the audit to obtain reasonable assurance about whether the
consolidated balance sheet is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated balance sheet, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall
consolidated balance sheet presentation. We believe that our audit provides a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
September 7, 1999
F-77
<PAGE>
PLAINS ALL AMERICAN INC.
CONSOLIDATED BALANCE SHEET
(in thousands, except share data)
<TABLE>
<CAPTION>
December 31,
1998
------------
<S> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents........................................ $ 6,408
Accounts receivable.............................................. 120,050
Due from affiliates.............................................. 1,655
Inventory ....................................................... 37,711
Prepaid expenses and other....................................... 605
--------
166,429
--------
PROPERTY AND EQUIPMENT
Property and equipment........................................... 378,835
Less accumulated depreciation and amortization................... (799)
--------
378,036
--------
OTHER ASSETS
Pipeline linefill................................................ 54,511
Other............................................................ 22,996
--------
$621,972
========
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable................................................. $137,416
Interest payable................................................. 1,298
Due to affiliates................................................ 4,502
Notes payable and current maturities of long-term debt........... 9,750
--------
Total current liabilities........................................ 152,966
LONG-TERM LIABILITIES
Bank debt........................................................ 175,000
Other............................................................ 45
Minority interest................................................ 243,498
--------
Total liabilities................................................ 571,509
--------
STOCKHOLDER'S EQUITY
Common Stock, $.01 par value, 1,000 shares authorized; issued and
outstanding 100 shares.......................................... --
Additional paid-in-capital....................................... 38,727
Retained earnings................................................ 11,736
--------
50,463
--------
$621,972
========
</TABLE>
See notes to consolidated balance sheet.
F-78
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET
Note 1--Organization, Basis of Consolidation and Accounting Policies
Organization
Plains All American Inc. ("PAAI") is a wholly owned subsidiary of Plains
Resources Inc. ("Plains Resources") which was originally formed in 1998 to
acquire, own and operate the All American Pipeline and the SJV Gathering System
(the "All American Acquisition") acquired from Wingfoot Ventures Seven, Inc.
("Wingfoot"), a wholly owned subsidiary of the Goodyear Tire and Rubber Company
("Goodyear") for approximately $400 million. The All American Acquisition was
effective July 30, 1998 and financed in part through a borrowing of $300
million under PAAI's bank facility with the remainder founded by a capital
contribution from Plains Resources.
During the third quarter of 1998, Plains All American Pipeline, L.P. (the
"Partnership" or "PAA") was formed to acquire and operate the midstream crude
oil business and assets of certain wholly owned subsidiaries of Plains
Resources, including PAAI (the "Plains Midstream Subsidiaries"). 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 in cash and the assumption of $11.0 million of
related indebtedness. Concurrent with the Transactions, PAAI 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 PAAI (the "General Partner") in connection with the
All American Acquisition.
In addition, the Partnership distributed approximately $177.6 million to
PAAI and used approximately $3 million of the remaining proceeds to pay
expenses incurred in connection with the Transactions. PAAI used $121.0 million
of the cash distributed to it to retire the remaining indebtedness incurred in
connection with the All American Acquisition and to pay other costs associated
with the Transactions. The balance, $56.6 million, was distributed to Plains
Resources.
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 PAAI.
PAA 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 (the SJV Gathering System). PAA also owns and operates a two
million barrel, above-ground crude oil terminalling and storage facility in
Cushing, Oklahoma.
F-79
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
Basis of Consolidated and Presentation
The consolidated balance sheet includes the accounts of PAAI and PAA, in
which PAAI has an approximate 57.4% effective ownership interest at December
31, 1998 and serves as its sole general partner. In May 1999, PAAI increased
its ownership interest in PAA to 59.2% (See Note 12). For financial statement
purposes, the assets, liabilities and earnings of PAA are included in PAAI's
consolidated financial statements, with the public unitholders' interest
reflected as a minority interest. All material intercompany accounts and
transactions have been eliminated. The following significant accounting
policies are followed by PAAI in the preparation of the consolidated balance
sheet.
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.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested
in highly liquid instruments.
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 are
included in interest and other income.
Pipeline linefill is recorded at cost and consists of crude oil linefill
used to pack a pipeline such that when an incremental barrel enters a pipeline
it forces a barrel out at another location. At December 31, 1998, the
F-80
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
Partnership owned approximately 5.0 million barrels of crude oil that is used
to maintain the All American Pipeline's linefill requirements.
The following is a summary of the components of property and equipment:
<TABLE>
<CAPTION>
December 31,
1998
--------------
(in thousands)
<S> <C>
Crude oil pipelines......................................... $268,219
Crude oil pipeline facilities............................... 70,870
Crude oil storage and terminal facilities................... 34,606
Trucking equipment, injection stations and other............ 5,140
--------
378,835
Less accumulated depreciation and amortization.............. (799)
--------
$378,036
========
</TABLE>
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:
<TABLE>
<CAPTION>
December 31,
1998
--------------
(in thousands)
<S> <C>
Debt issue costs............................................ $10,171
Receivable in lieu of deferred taxes........................ 12,186
Goodwill and other.......................................... 1,134
-------
23,491
Accumulated amortization.................................... (495)
-------
$22,996
=======
</TABLE>
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. Debt issue costs are related to debt incurred at the time of 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 and is
amortized using the straight-line method over a period of twenty years.
Federal Income Taxes
PAAI is included in the combined federal income tax return of Plains
Resources. Income taxes are calculated as if PAAI had filed a return on a
separate company basis utilizing a federal statutory rate of 35%. Included in
Other Assets is a receivable in lieu of deferred taxes which represents
deferred tax assets which are recognized based on the temporary differences
between the tax basis of PAAI's assets and liabilities and the amounts reported
in the financial statements. These amounts were owed by Plains Resources.
Current amounts payable are owed to Plains Resources and are included in due to
affiliates in the accompanying consolidated balance sheet.
F-81
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
Hedging
The Partnership utilizes various derivative instruments, for purposes other
than trading, to hedge its exposure to price fluctuations on crude oil 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 Merchantile 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.
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 sheet. 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.
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, 2000. 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 PAAI or 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 PAAI or the Partnership is hedging the
variability of cash flows related to a variable-rate asset, liability, or a
forcasted 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. PAAI is required to adopt
this statement beginning in 2001. PAAI 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
F-82
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
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 PAAI beginning in 1999. The adoption of this consensus is not expected to
have a material impact on PAAI's results of operations or financial position.
Note 2--Acquisition
Effective July 30, 1998, PAAI 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 consolidated financial statements of
PAAI effective July 30, 1998. The purchase price was allocated in accordance
with Accounting Principles Board Opinion No. 16 ("APB 16") as follows (in
thousands):
<TABLE>
<S> <C>
Crude oil pipeline, gathering and terminal assets................ $392,528
Other assets (debt issue costs).................................. 6,138
Net working capital items (excluding cash received of $7,481).... 1,498
--------
Cash paid........................................................ $400,164
========
</TABLE>
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. At December 31, 1998, the Partnership had 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.
At December 31, 1998, the Partnership had $175 million outstanding under the
Term Loan Facility, which amount represents indebtedness assumed from PAAI. 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.
F-83
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
Letter of Credit Facility. In connection with the IPO, the Partnership
entered into a $175 million letter of credit 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
Plains Midstream Subsidiaries' 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 primarily 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%.
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. To date,
no amounts have been drawn on such letters of credit.
Both the Letter of Credit Facility and the Bank Credit Agreement contain a
prohibition on distributions on, or purchases or redemptions of Partnership
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 Distributions
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
F-84
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
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 Subordinated 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.
On May 14, 1999, the Partnership paid a cash distribution of $0.45 per unit
on its outstanding Common Units and Subordinated Units. The distribution was
paid to holders of record of Common Units and Subordinated Units at the close
of business on May 3, 1999. The total distribution paid was approximately $13.8
million, with approximately $5.9 million paid to the Partnership's public
Unitholders, and the remainder paid to PAAI for its limited partner and general
partner interests. This distribution was the first full quarterly distribution
since the Partnership was formed.
On August 13, 1999, the Partnership paid a cash distribution of $0.4625 per
unit on its outstanding Common Units, Class B Units and Subordinated Units. The
distribution was paid to holders of record of such Units on August 3, 1999. The
total distribution paid was approximately $14.9 million, with approximately
$6.1 million paid to the Partnership's public Unitholders and the remainder
paid to PAAI for its limited and general partner interests. This distribution
represents an increase of $.0125 per unit over the minimum quarterly
distribution of $0.45 per unit.
Note 5--Concentration of Credit Risk
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 PAAI and Plains
Resources. PAAI does not receive a management fee or other compensation in
connection with its management of the Partnership. The Partnership reimburses
PAAI 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
F-85
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
or appropriate to the conduct of the business of, and allocable to the
Partnership. The Partnership Agreement provides that PAAI will determine the
expenses that are allocable to the Partnership in any reasonable manner
determined by PAAI in its sole discretion. Total costs reimbursed to PAAI 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 PAAI
in Plains Resources' offices in Houston, Texas and (iii) out-of-pocket expenses
related to the provisions 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 the
Partnership 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 revenues
for such period.
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 to 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 and 2000, 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 Partnership's
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-86
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
At December 31, 1998, the Partnership had two 10-year interest rate swaps
(subject to cancellation by the counterparty after seven years) aggregating a
notional principal amount of $175 million which fixed 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:
<TABLE>
<CAPTION>
December 31,
1998
----------------
Carrying Fair
Amount Value
-------- -------
(in thousands)
<S> <C> <C>
Unrealized loss on interest rate swaps.................. $ -- $(2,164)
</TABLE>
Note 8--Commitments and Contingencies
The Partnership leases office space under leases accounted for as operating
leases. 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. 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. We
have expended approximately $400,000 to date in connection with this spill and
do not expect any additional expenditures to be material. The Partnership does
not believe the ultimate resolution of this issue will have a material adverse
effect on PAAI's consolidated financial position.
Prior to being acquired by the Plains Midstream Subsidiaries 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 effect on PAAI's consolidated financial
position.
F-87
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
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.
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--Long-Term Incentive Plans
The Plains All American Inc. 1998 Long-Term Incentive Plan (the "Long-Term
Incentive Plan") was adopted for employees and directors of PAAI 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 PAAI'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 PAAI 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 PAAI will be eligible to
vest prior to termination of the Subordination Period. There have been no
grants to non-employee 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 PAAI in the open market, Common Units already owned by PAAI, Common
Units acquired by PAAI directly from the Partnership or any other person, or
any combination of the foregoing. PAAI 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. A
tandem distribution equivalent right is a contingent right, granted in tandem
with a specific Restricted Unit, to receive an amount in cash equal to the cash
distributions made by the Partnership with respect to a Unit during the period
such Restricted Unit is outstanding.
The issuance of the Common units pursuant to the Restricted Unit Plan is
intended to serve as 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-88
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
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, PAAI 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
PAAI, or any combination of the foregoing. PAAI will be entitled to
reimbursement by the Partnership for the difference between the cost incurred
by PAAI in acquiring such Common Units and the proceeds received by PAAI 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 PAAI 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, PAAI 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 PAAI who perform services for
the Partnership (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 Partnership's 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, Restricted Units and Transaction Grants described above when
vesting becomes probable.
Note 10--Operating Segments
PAAI'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, PAAI had only marketing, gathering, terminalling and
storage operations.
F-89
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
The accounting policies of the segments are the same as those described in
Note 1. The following summarizes certain balance sheet related disclosures for
the segments.
<TABLE>
<CAPTION>
Marketing,
Gathering,
Terminalling
(In thousands) Pipeline & Storage Total
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Year Ended December 31, 1998
Capital Expenditures......................... $393,731 $7,212 $400,943
</TABLE>
Note 11--Income Taxes
As discussed in Note 1, PAAI's results are included in Plains Resources'
combined federal income tax return. The income taxes presented for PAAI are
reported as if it had filed its return on a separate return basis. Current
amounts payable for income taxes of $4.5 million at December 31, 1998 are
included in due to affiliates.
PAAI has recorded a receivable in lieu of deferred taxes (included in other
assets) of approximately $12.2 million at December 31, 1998 relating to the
difference between its tax basis and its book basis in its investment in the
Partnership. Management believes that it is more likely than not that PAAI will
generate taxable income sufficient to realize such asset based on past
financial performance of the Partnership's operating assets and future
projected taxable income.
Note 12--Subsequent Events
Scurlock Acquisition
On May 12, 1999, Plains Scurlock, a limited partnership of which PAAI is the
general partner and Plains Marketing, L.P. is the limited partner, completed
the acquisition of Scurlock Permian LLC ("Scurlock") and certain other pipeline
assets (the "Scurlock Acquisition") from Marathon Ashland Petroleum LLC
("MAP"). Including working capital adjustments and associated closing and
financing costs, the cash purchase price was approximately $141 million.
Scurlock, previously a wholly owned subsidiary of MAP, 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 250 trucks. Its largest asset is an 800-mile pipeline and gathering
system located in the Spraberry Trend in West Texas that extends into Andrews,
Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets
acquired also include approximately 2.4 million barrels of crude oil.
Financing for the Scurlock Acquisition was provided through (i) a borrowing
of approximately $92 million under Plains Scurlock's limited recourse bank
facility with BankBoston, N.A. (the "Plains Scurlock Credit Facility"), (ii)
the sale to PAAI of 1.3 million Class B Common Units ("Class B Units") of PAA
at $19.125 per unit, the price equal to the market value of PAA's common units
("Common Units") on May 12, 1999, for a total cash consideration of $25 million
and (iii) a $25 million draw under PAA's existing revolving credit agreement.
The Plains Scurlock Credit Facility consists of (i) a five-year $126.6
million term loan and (ii) a three-year $35 million revolving credit facility.
The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains Marketing,
L.P. and All American Pipeline, L.P. and is secured by the assets acquired.
Borrowings under the
F-90
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
term loan bear interest at the London Interbank Offering Rate ("LIBOR") plus 3%
and under the revolving credit facility at LIBOR plus 2.75%. A commitment fee
equal to one-half of one percent per year is charged on the unused portion of
the revolving credit facility. The revolving credit facility, which may be used
for borrowings or letters of credit to support crude oil purchases, matures in
May 2002. The term loan provides for principal amortization of $0.7 million
annually beginning May 2000, with a final maturity of May 2004. As of June 30,
1999, letters of credit of approximately $15.2 million were outstanding under
the revolver and borrowings of $90 million were outstanding under the term
loan.
The Class B Units are initially pari passu with Common Units with respect to
distributions, and after six months are convertible into Common Units upon
approval of a majority of Common Unitholders. After such six month period, the
Class B Unitholder may request that PAA call a meeting of Common Unitholders to
consider approval of the conversion of Class B Units into Common Units. If the
approval of such conversion by the Common Unitholders is not obtained within
120 days of such request (the "Initial Approval Period"), the Class B
Unitholders will be entitled to receive distributions, on a per Unit basis,
equal to 110% of the amount of distributions paid on a Common Unit, with such
distribution right increasing to 115% if such approval is not secured within 90
days after the end of the Initial Approval Period. Except for the vote to
approve conversion, Class B Units have the same voting rights as the Common
Units.
The assets, liabilities and results of operations of Scurlock are included
in the Consolidated Financial Statements effective May 1, 1999. The Scurlock
Acquisition has been accounted for using the purchase method of accounting and
the purchase price was allocated in accordance with APB 16 as follows:
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Crude oil pipeline, gathering and terminal assets.......... $124,615
Other property and equipment............................... 1,546
Pipeline linefill.......................................... 16,057
Other assets (debt issue costs)............................ 3,100
Environmental accrual...................................... (1,000)
Net working capital items.................................. (3,090)
--------
Cash paid.................................................. $141,228
========
</TABLE>
The purchase price allocation was based on preliminary estimates of fair
value and is subject to adjustment as additional information becomes available
and is evaluated. The purchase accounting entries include a $1.0 million
accrual for estimated environmental remediation costs. Under the agreement for
the sale of Scurlock by MAP to Plains Scurlock Permian, L.P. ("Plains
Scurlock"), MAP has agreed to indemnify and hold harmless Scurlock and Plains
Scurlock for claims, liabilities and losses (collectively "Losses") resulting
from any act or omission attributable to Scurlock's business or properties
occurring prior to the date of the closing of such sale to the extent the
aggregate amount of such Losses exceed $1.0 million; provided however, that
claims for such Losses must individually exceed $25,000 and must be asserted by
Scurlock against MAP on or before May 15, 2003.
Chevron Asset Acquisition
On July 15, 1999, Plains Scurlock completed the acquisition of a West Texas
crude oil pipeline and gathering system from Chevron Pipe Line Company for
approximately $36.6 million, including transaction costs (the "Chevron Asset
Acquisition"). The principal assets acquired include approximately 450 miles of
crude oil transmission mainlines, approximately 340 miles of associated
gathering and lateral lines and approximately 2.9 million barrels of crude oil
storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and
Winkler Counties, Texas. Financing for the Chevron Asset Acquisition was
provided by a draw of $36.6 million under the term loan portion of the Plains
Scurlock Credit Facility.
F-91
<PAGE>
PLAINS ALL AMERICAN INC.
NOTES TO CONSOLIDATED BALANCE SHEET--(Continued)
Chevron U.S.A. Inc., which currently transports approximately 26,000 barrels
of crude oil per day on the system, will continue to transport its equity crude
oil production from the region on the system under a twelve-year contractual
arrangement.
In March 1999, the Partnership adopted a plan to reduce staff in its
pipeline operations and to relocate certain functions. The Partnership incurred
a charge to first quarter earnings of approximately $410,000 in connection with
such plan.
F-92
<PAGE>
APPENDIX A
GLOSSARY OF CERTAIN TERMS
adjusted operating surplus: For any period, operating surplus generated
during that period as adjusted to:
(a) decrease operating surplus by:
(1) any net increase in working capital borrowings during that period;
and
(2) any net reduction in cash reserves for operating expenditures during
that period not relating to an operating expenditure made during
that period; and
(b) increase operating surplus by:
(1) any net decrease in working capital borrowings during that period;
and
(2) any net increase in cash reserves for operating expenditures during
that period required by any debt instrument for the repayment of
principal, interest or premium.
Adjusted operating surplus does not include that portion of operating
surplus included in clause (a)(1) of the definition of operating surplus.
available cash: For any quarter prior to liquidation:
(a) the sum of:
(1) all cash and cash equivalents of Plains All American Pipeline on
hand at the end of that quarter; and
(2) all additional cash and cash equivalents of Plains All American
Pipeline on hand on the date of determination of available cash for
that quarter resulting from working capital borrowings after the end
of that quarter;
(b) less the amount of cash reserves that is necessary or appropriate in
the reasonable discretion of the general partner to:
(1) provide for the proper conduct of the business of Plains All
American Pipeline (including reserves for future capital
expenditures) after that quarter;
(2) comply with applicable law or any debt instrument or other agreement
or obligation to which any member of Plains All American Pipeline is
a party or its assets are subject; and
(3) provide funds for minimum quarterly distributions and cumulative
common unit arrearages for any one or more of the next four
quarters;
provided, however, that the general partner may not establish cash reserves
for distributions to the subordinated units unless the general partner has
determined that in its judgment the establishment of reserves will not prevent
Plains All American Pipeline from distributing the minimum quarterly
distribution on all common units and any common unit arrearages thereon for
the next four quarters; and,
provided further, that disbursements made by Plains All American Pipeline
and its subsidiaries or cash reserves established, increased or reduced after
the end of that quarter but on or before the date of determination of
available cash for that quarter shall be deemed to have been made,
established, increased or reduced, for purposes of determining available cash,
within that quarter if the general partner so determines.
barrel: One barrel of crude oil equals 42 U.S. gallons.
capital account: The capital account maintained for a partner under the
partnership agreement. The capital account of a partner for a common unit, a
subordinated unit, an incentive distribution right or any other
A-1
<PAGE>
partnership interest will be the amount which that capital account would be if
that common unit, subordinated unit, incentive distribution right or other
partnership interest were the only interest in Plains All American Pipeline
held by a partner.
capital surplus: All available cash distributed by us from any source will
be treated as distributed from operating surplus until the sum of all available
cash distributed since the closing of the initial public offering equals the
operating surplus as of the end of the quarter before that distribution. Any
excess available cash will be deemed to be capital surplus.
closing price: The last sale price on a day, regular way, or in case no sale
takes place on that day, the average of the closing bid and asked prices on
that day, regular way. In either case, as reported in the principal
consolidated transaction reporting system for securities listed or admitted to
trading on the principal national securities exchange on which the units of
that class are listed or admitted to trading. If the units of that class are
not listed or admitted to trading on any national securities exchange, the last
quoted price on that day. If no quoted price exists, the average of the high
bid and low asked prices on that day in the over-the-counter market, as
reported by the Nasdaq Stock Market or any other system then in use. If on any
day the units of that class are not quoted by any organization of that type,
the average of the closing bid and asked prices on that day as furnished by a
professional market maker making a market in the units of the class selected by
the board of directors of the general partner. If on that day no market maker
is making a market in the units of that class, the fair value of the units on
that day as determined reasonably and in good faith by the board of directors
of the general partner.
common unit arrearage: The amount by which the minimum quarterly
distribution for a quarter during the subordination period exceeds the
distribution of available cash from operating surplus actually made for that
quarter on a common unit, cumulative for that quarter and all prior quarters
during the subordination period.
current market price: For any class of units listed or admitted to trading
on any national securities exchange as of any date, the average of the daily
closing prices for the 20 consecutive trading days immediately prior to that
date.
incentive distribution right: A non-voting limited partner partnership
interest issued to the general partner in connection with the transfer of
substantially all of its general partner interest in the operating partnerships
to Plains All American Pipeline under the partnership agreement. The
partnership interest will confer upon its holder only the rights and
obligations specifically provided in the partnership agreement for incentive
distribution rights.
incentive distributions: The distributions of available cash from operating
surplus initially made to the general partner that are in excess of the general
partner's aggregate 2% general partner interest.
interim capital transactions: The following transactions if they occur prior
to liquidation:
(a) borrowings, refinancings or refundings of indebtedness and sales of
debt securities (other than for working capital borrowings and
other than for items purchased on open account in the ordinary
course of business) by Plains All American Pipeline;
(b) sales of equity interests by Plains All American Pipeline; and
(c) sales or other voluntary or involuntary dispositions of any assets
of Plains All American Pipeline (other than sales or other
dispositions of inventory, accounts receivable and other assets in
the ordinary course of business, and sales or other dispositions of
assets as a part of normal retirements or replacements).
A-2
<PAGE>
operating expenditures: All expenditures of Plains All American Pipeline and
our subsidiaries, including, but not limited to, taxes, reimbursements of the
general partner, debt service payments and capital expenditures, subject to the
following:
(a) Payments (including prepayments) of principal of and premium on
indebtedness will not be an operating expenditure if the payment is
required in connection with the sale or other disposition of assets or
made in connection with the refinancing or refunding of indebtedness
with the proceeds from new indebtedness or from the sale of equity
interests.
(b) Operating expenditures will not include:
(1) capital expenditures made for acquisitions or for capital
improvements;
(2) payment of transaction expenses relating to interim capital
transactions; or
(3) distributions to partners.
operating surplus: For any period prior to liquidation, on a cumulative
basis and without duplication:
(a) the sum of:
(1) $29 million;
(2) all cash receipts of Plains All American Pipeline and our
subsidiaries for the period beginning on the closing date of our
initial public offering and ending with the last day of that
period, other than cash receipts from interim capital transactions;
and
(3) all cash receipts of Plains All American Pipeline and our
subsidiaries after the end of that period but on or before the date
of determination of operating surplus for the period resulting from
working capital borrowings; less
(b) the sum of:
(1) operating expenditures for the period beginning on the closing date
of our initial public offering and ending with the last day of that
period; and
(2) the amount of cash reserves that is necessary or advisable in the
reasonable discretion of the general partner to provide funds for
future operating expenditures; provided however, that disbursements
made (including contributions to a member of Plains All American
Pipeline and our subsidiaries or disbursements on behalf of a
member of Plains All American Pipeline and our subsidiaries) or
cash reserves established, increased or reduced after the end of
that period but on or before the date of determination of available
cash for that period shall be deemed to have been made,
established, increased or reduced for purposes of determining
operating surplus, within that period if the general partner so
determines.
subordination period: The subordination period will generally extend from
the closing of the initial public offering until the first to occur of:
(a) the first day of any quarter beginning after December 31, 2003 for
which:
(1) distributions of available cash from operating surplus on each of
the outstanding common units and subordinated units equaled or
exceeded the sum of the minimum quarterly distribution on all of
the outstanding common units and subordinated units for each of the
three non-overlapping four-quarter periods immediately preceding
that date;
(2) the adjusted operating surplus generated during each of the three
immediately preceding, non-overlapping four-quarter periods equaled
or exceeded the sum of the minimum quarterly distribution on all of
the common units and subordinated units that were outstanding
during those periods on a fully-diluted basis, and the related
distribution on the general partner interests in Plains All
American Pipeline and the operating partnerships; and
A-3
<PAGE>
(3) there are no outstanding common unit arrearages.
(b) the date on which the general partner is removed as general partner of
Plains All American Pipeline upon the requisite vote by limited
partners under circumstances where cause does not exist and units held
by the general partner and its affiliates are not voted in favor of
the removal.
working capital borrowings: Borrowings exclusively for working capital
purposes made pursuant to a credit facility or other arrangement requiring all
borrowings thereunder to be reduced to a relatively small amount each year for
an economically meaningful period of time.
A-4
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2,600,000 Common Units
Plains All American Pipeline, L.P.
Representing
Limited Partner Interests
[Plains All America Pipeline Logo]
--------
PROSPECTUS
, 1999
--------
Salomon Smith Barney
Goldman, Sachs & Co.
A.G. Edwards & Sons, Inc.
First Union Capital Markets Corp.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
Set forth below are the expenses (other than underwriting discounts and
commissions) expected to be incurred in connection with the issuance and
distribution of the securities registered hereby. With the exception of the
Securities and Exchange Commission registration fee, the NASD filing fee and
the NYSE filing fee, the amounts set forth below are estimates:
<TABLE>
<S> <C>
Securities and Exchange Commission registration fee................. $16,467
NASD filing fee..................................................... 6,424
NYSE listing fee.................................................... 36,000
Printing and engraving expenses..................................... *
Legal fees and expenses............................................. *
Accounting fees and expenses........................................ *
Transfer agent and registrar fees................................... *
Miscellaneous....................................................... *
-------
TOTAL............................................................. $ *
=======
</TABLE>
- --------
*To be added by amendment.
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS
The section of the prospectus entitled "The Partnership Agreement --
Indemnification" is incorporated herein by this reference. Reference is made to
Section 7 of the Underwriting Agreement filed as Exhibit 1.1 to the
Registration Statement. Subject to any terms, conditions or restrictions set
forth in the Partnership Agreement, Section 17-108 of the Delaware Revised
Uniform Limited Partnership Act empowers a Delaware limited partnership to
indemnify and hold harmless any partner or other person from and against all
claims and demands whatsoever.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES
We issued 6,974,239 common units and 10,029,619 subordinated units to a
subsidiary of our general partner in connection with our formation on September
17, 1998 pursuant to transactions exempt from registration under Section 4(2)
of the Securities Act of 1933. On May 12, 1999, we issued 1,307,190 Class B
common units to the general partner pursuant to a transaction that is exempt
from registration pursuant to Section 4(2) of the Securities Act. We have not
sold any other unregistered securities within the past three years.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
a. Exhibits:
<TABLE>
<C> <C> <S>
1.1** -- Form of Underwriting Agreement
3.1 -- Second Amended and Restated Agreement of Limited Partnership of
Plains All American Pipeline, L.P. (incorporated by reference to
Exhibit 3.1 to the registrant's Annual Report on Form 10-K filed
on March 31, 1999)
3.2 -- Amended and Restated Agreement of Limited Partnership of Plains
Marketing, L.P. (incorporated by reference to Exhibit 3.2 to the
registrant's Annual Report on Form 10-K filed on March 31, 1999)
3.3 -- Amended and Restated Agreement of Limited Partnership of All
American Pipeline, L.P. (incorporated by reference to Exhibit 3.3
to the registrant's Annual Report on Form 10-K filed on March 31,
1999)
</TABLE>
II-1
<PAGE>
<TABLE>
<C> <C> <S>
3.4 -- Certificate of Limited Partnership of Plains All American
Pipeline, L.P. (incorporated by reference to Exhibit 3.4 to
registrant's Registration Statement on Form S-1, file no. 333-
64107)
3.5 -- Certificate of Limited Partnership of Plains Marketing, L.P.
(incorporated by reference to Exhibit 3.5 to the registrant's
Annual Report on Form 10-K filed on March 31, 1999)
3.6 -- Articles of Conversion of All American Pipeline, L.P.
(incorporated by reference to Exhibit 3.6 to the registrant's
Annual Report on Form 10-K filed on March 31, 1999)
3.7 -- Agreement of Limited Partnership of Plains Scurlock Permian, L.P.
(incorporated by reference to Exhibit 3.7 to the registrant's
Quarterly Report on Form 10-Q filed on May 14, 1999)
3.8 -- Amendment No. 1 to the Second Amended and Restated Agreement of
Limited Partnership of Plains All American Pipeline, L.P.
(incorporated by reference to Exhibit 3.8 to the registrant's
Quarterly Report on Form 10-Q filed on August 16, 1999)
5.1** -- Opinion of Andrews & Kurth L.L.P. as to the legality of the
securities being registered
8.1** -- Opinion of Andrews & Kurth L.L.P. relating to tax matters
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 (incorporated by
reference to Exhibit 10.1 to the registrant's Annual Report on
Form 10-K filed on March 31, 1999)
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 (incorporated by
reference to Exhibit 10.2 to the registrant's Annual Report on
Form 10-K filed on March 31, 1999)
10.3 -- Contribution, Conveyance and Assumption Agreement among Plains All
American Pipeline, L.P. and certain other parties (incorporated by
reference to Exhibit 10.3 to the registrant's Annual Report on
Form 10-K filed on March 31, 1999)
10.4 -- Plains All American Inc. 1998 Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.4 to the registrant's
Annual Report on Form 10-K filed on March 31, 1999)
10.5 -- Plains All American Inc. Management Incentive Plan (incorporated
by reference to Exhibit 10.5 to the registrant's Annual Report on
Form 10-K filed on March 31, 1999)
10.6 -- Employment Agreement between Plains Resources Inc. and Harry N.
Pefanis (incorporated by reference to Exhibit 10.6 to the
registrant's Annual Report on Form 10-K filed on March 31, 1999)
10.7 -- Crude Oil Marketing Agreement between Plains Resources Inc.,
Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida,
Inc. and Plains Marketing, L.P.(incorporated by reference to
Exhibit 10.7 to the registrant's Annual Report on Form 10-K filed
on March 31, 1999)
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. (incorporated by reference to
Exhibit 10.8 to the registrant's Annual Report on Form 10-K filed
on March 31, 1999)
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 registrant's Registration Statement
on Form S-1, file no. 333-64107)
10.10 -- Transportation Agreement dated August 2, 1993 among All American
Pipeline Company, Texaco Trading and Transportation Inc., Chevron
U.S.A. and Sun Operating Limited Partnership (incorporated by
reference to Exhibit 10.10 to registrant's Registration Statement
on Form S-1, file no. 333-64107)
10.11 -- Form of Transaction Grant Agreement (Deferred Payment)
(incorporated by reference to Exhibit 10.11 to registrant's
Registration Statement on Form S-1, file no. 333-64107)
10.12 -- Form of Transaction Grant Agreement (Payment on Vesting)
(incorporated by reference to Exhibit 10.12 to registrant's
Registration Statement on Form S-1, file no. 333-64107)
10.13 -- First Amendment to Contribution, Conveyance and Assumption
Agreement dated as of December 15, 1998 (incorporated by reference
to Exhibit 10.13 to the registrant's Annual Report on Form 10-K
filed on March 31, 1999)
</TABLE>
II-2
<PAGE>
<TABLE>
<C> <C> <S>
10.14 -- First Amendment dated as of March 18, 1999, to Credit Agreement
among All American Pipeline, L.P. Plains Marketing, L.P., ING
(U.S.) Capital Corporation and certain other banks
(incorporated by reference to Exhibit 10.14 to the registrant's
Annual Report on Form 10-K filed on March 31, 1999)
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., Bank
Boston, N.A. and certain other banks (incorporated by reference
to Exhibit 10.15 to the registrant's Annual Report on Form 10-K
filed on March 31, 1999)
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 (incorporated by
reference to Exhibit 10.16 to the registrant's Annual Report on
Form 10-K filed on March 31, 1999)
10.17 -- Asset Sales Agreement between Chevron Pipe Line Company and
Plains Marketing, L.P. dated April 16, 1999 (incorporated by
reference to Exhibit 10.17 to the registrant's Quarterly Report
on Form 10-Q filed on May 14, 1999)
10.18 -- Credit Agreement dated as of May 12, 1999, between Plains
Scurlock Permian, L.P. BankBoston, N.A. and certain financial
institutions (incorporated by reference to Exhibit 10.18 to the
registrant's Quarterly Report on Form 10-Q filed on May 14,
1999)
10.19 -- First Amendment to Credit Agreement dated as of July 29, 1999
between Plains Scurlock Permian, L.P., BankBoston, N.A. and
certain financial institutions (incorporated by reference to
Exhibit 10.19 to the registrant's Quarterly Report on Form 10-Q
filed on August 16, 1999)
10.20*** -- Transaction Grant Agreement with Greg L. Armstrong
10.21*** -- Second Amendment to Credit Agreement dated as of August 19,
1999, between Plains Scurlock Permian, L.P., BankBoston, N.A.
and certain financial institutions
15.1* -- Letter re unaudited interim financial information (relating to
financial information of Wingfoot Ventures Seven, Inc.)
21.1*** -- List of subsidiaries of the Partnership
23.1* -- Consent of PricewaterhouseCoopers LLP (relating to financial
statements of Plains All American Inc., Plains Midstream
Subsidiaries and Plains All American Pipeline, L.P.)
23.2* -- Consent of PricewaterhouseCoopers LLP (relating to financial
statements of Wingfoot Ventures Seven, Inc.)
23.3* -- Consent of PricewaterhouseCoopers LLP (relating to financial
statements of the Scurlock Permian Businesses)
23.4** -- Consent of Andrews & Kurth L.L.P. (contained in Exhibits 5.1
and 8.1)
24.1 -- Powers of Attorney (included on the signature page)
</TABLE>
- --------
*Filed herewith
**To be filed by amendment
*** Previously filed
(b) Financial Statement Schedules
All financial statement schedules are omitted because the information is not
required, is not material or is otherwise included in the financial statements
or related notes thereto.
ITEM 17. UNDERTAKINGS
The undersigned Registrant hereby undertakes to provide at the closing
specified in the underwriting agreement certificates in such denominations and
registered in such names as required by the Underwriters to permit prompt
delivery to each purchaser.
II-3
<PAGE>
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities
Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with the
securities being registered, the Registrant will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act and will be governed
by the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act,
the information omitted from the form of prospectus filed as part of this
Registration Statement in reliance upon Rule 430A and contained in a form
of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or
497(h) under the Securities Act shall be deemed to be part of this
Registration Statement as of the time it was declared effective.
(2) For the purposes of determining any liability under the Securities
Act, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
II-4
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this amendment to the Registration Statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the City
of Houston, State of Texas, on September 22, 1999.
PLAINS ALL AMERICAN PIPELINE, L.P.
By: Plains All American Inc.,its
general partner
Greg L. Armstrong*
By___________________________________
Name: Greg L. Armstrong
Title: Chairman of the Board and
Chief Executive Officer
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, AS AMENDED, THIS
REGISTRATION STATEMENT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS IN THE
CAPACITIES AND ON THE DATES INDICATED BELOW.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<C> <S> <C>
Greg L. Armstrong* Chairman of the Board, September 22, 1999
____________________________________ Chief Executive Officer and
Greg L. Armstrong Director (Principal
Executive Officer)
Harry N. Pefanis* President, Chief Operating September 22, 1999
____________________________________ Officer and Director
Harry N. Pefanis
Phillip D. Kramer* Executive Vice President and September 22, 1999
____________________________________ Chief Financial Officer
Phillip D. Kramer (Principal Financial
Officer)
Cynthia A. Feeback* Treasurer (Principal September 22, 1999
____________________________________ Accounting Officer)
Cynthia A. Feeback
Everardo Goyanes* Director September 22, 1999
____________________________________
Everardo Goyanes
Robert V. Sinnott* Director September 22, 1999
____________________________________
Robert V. Sinnott
Arthur L. Smith* Director September 22, 1999
____________________________________
Arthur L. Smith
</TABLE>
/s/ Michael R. Patterson
*By: __________________________
Michael R. Patterson,
By Power of Attorney
II-5
<PAGE>
EXHIBIT 15.1
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Commissioners:
We are aware that our report dated September 23, 1998 on our review of
interim financial information of Wingfoot Ventures Seven, Inc. as of June 30,
1998 and for the six-month periods ended June 30, 1998 and 1997 is included in
Plains All American Pipeline, L.P.'s Registration Statement on Form S-1 to be
filed on or about September 21, 1999.
Yours very truly,
/s/ PricewaterhouseCoopers LLP
San Francisco, California
September 21, 1999
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the use in this Registration Statement on Form S-1 of
our reports dated March 29, 1999, March 29, 1999, and September 7, 1999 relating
to the consolidated financial statements of Plains All American Pipeline, L.P.,
the combined financial statements of Plains Resources Inc. Midstream
Subsidiaries, and the consolidated balance sheet of Plains All American Inc.,
respectively, which appear in such Registration Statement. We also consent to
the reference to us under the heading "Experts" in such Registration Statement.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
September 21, 1999
<PAGE>
EXHIBIT 23.2
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the use in this Registration Statement on Form S-1 of
our report dated July 27, 1998 relating to the consolidated financial statements
of Wingfoot Ventures Seven, Inc., which appears in such Registration Statement.
We also consent to the reference to us under the heading "Experts" in such
Registration Statement.
/s/ PricewaterhouseCoopers LLP
San Francisco, California
September 21, 1999
<PAGE>
EXHIBIT 23.3
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the use in this Registration Statement on Form S-1 of
our reports dated April 30, 1999 relating to financial statements of the
Scurlock Permian Businesses and Scurlock Permian Corporation, respectively,
which appear in such Registration Statement. We also consent to the reference to
us under the heading "Experts" in such Registration Statement.
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
September 21, 1999
