As filed with the Securities and Exchange Commission on September 10, 1999 Registration No. 333- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------- 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. 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200 Attn: David P. Oelman ------------------------- 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 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Proposed Maximum Title of Each Class of Securities Aggregate Offering Amount of to be Registered Price(/1/)(/2/) Registration Fee - ------------------------------------------------------------------------------ Common units representing limited partner interests................................ $57,500,000 $15,985 - ------------------------------------------------------------------------------ (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). - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++ +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 10, 1999 PROSPECTUS 2,564,103 Common Units Plains All American Pipeline, L.P. Representing Limited Partner Interests $ per unit ----------- We are selling 2,564,103 common units. We are 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 384,615 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. 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 8, 1999, the last reported sale price on the New York Stock Exchange was $19.50 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. ----------- Per Common Unit Total --------------- ------------ Public Offering Price............................ $ $ Underwriting Discount............................ $ $ Proceeds, before expenses, to Plains All American Pipeline........................................ $ $ The underwriters expect to deliver the common units to purchasers on or about , 1999. ----------- , 1999
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 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 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 (i)
Regulation............................................................... 70 Pipeline Regulation.................................................... 70 Tariff Regulation...................................................... 70 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................................................................ 75 Legal Proceedings........................................................ 75 MANAGEMENT................................................................. 76 The General Partner Manages Plains All American Pipeline................. 76 Directors and Executive Officers of the General Partner.................. 76 Reimbursement of Expenses of the General Partner and its Affiliates...... 78 Executive Compensation................................................... 78 Employment Agreement..................................................... 78 Long-Term Incentive Plan................................................. 79 Transaction Grant Agreements............................................. 80 Management Incentive Plan................................................ 80 Compensation of Directors................................................ 80 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............. 81 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................. 83 Rights of the General Partner............................................ 83 Relationship with Plains Resources....................................... 83 CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES....................... 85 Conflicts of Interest.................................................... 85 Fiduciary Duties Owed to Unitholders by the General Partner are Prescribed by Law and the Partnership Agreement......................... 88 DESCRIPTION OF THE COMMON UNITS............................................ 90 The Units................................................................ 90 Transfer Agent and Registrar............................................. 90 Duties................................................................. 90 Resignation or Removal................................................. 90 Transfer of Common Units................................................. 90 Class B Common Units..................................................... 91 DESCRIPTION OF THE SUBORDINATED UNITS...................................... 92 Conversion of Subordinated Units......................................... 92 Limited Voting Rights.................................................... 93 Distributions upon Liquidation............................................ 93 THE PARTNERSHIP AGREEMENT................................................... 94 Organization and Duration................................................. 94 Purpose................................................................... 94 Power of Attorney......................................................... 94 Capital Contributions..................................................... 94 Limited Liability......................................................... 95 Issuance of Additional Securities......................................... 96 Amendment of the Partnership Agreement.................................... 96 Merger, Sale or Other Disposition of Assets............................... 98 Termination and Dissolution............................................... 99 Liquidation and Distribution of Proceeds.................................. 99 Withdrawal or Removal of the General Partner.............................. 99 Transfer of General Partner Interests and Incentive Distribution Rights... 101 Change of Management Provisions........................................... 101 Limited Call Right........................................................ 102 Meetings; Voting.......................................................... 102 Status as Limited Partner or Assignee..................................... 103 Non-citizen Assignees; Redemption......................................... 103 Indemnification........................................................... 103 Books and Reports......................................................... 104 Right to Inspect our Books and Records.................................... 104 Registration Rights....................................................... 105 UNITS ELIGIBLE FOR FUTURE SALE.............................................. 106 TAX CONSIDERATIONS.......................................................... 108 Legal Opinions and Advice................................................. 108 Partnership Status........................................................ 109 Limited Partner Status.................................................... 110 Tax Consequences of Unit Ownership........................................ 110 Tax Treatment of Operations............................................... 115 Disposition of Common Units............................................... 116 Uniformity of Units....................................................... 118 Tax-Exempt Organizations and Other Investors.............................. 119 Administrative Matters.................................................... 120 State, Local and Other Tax Considerations................................. 122 INVESTMENT IN PLAINS ALL AMERICAN PIPELINE BY EMPLOYEE BENEFIT PLANS........ 123 UNDERWRITING................................................................ 124 VALIDITY OF THE COMMON UNITS................................................ 126 EXPERTS..................................................................... 126 WHERE YOU CAN FIND MORE INFORMATION......................................... 127 FORWARD-LOOKING STATEMENTS.................................................. 127 INDEX TO FINANCIAL STATEMENTS............................................... F-1 APPENDIX A. GLOSSARY........................................................ A-1 (ii)
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 $19.50 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)
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 transporters, 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. 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
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, operated by a subsidiary of Plains Resources. 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 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 in crude oil transportation, gathering and marketing, and has more than 2,400 miles of active pipelines, numerous storage terminals and a fleet of more than 250 trucks. Scurlock's largest asset is an 800-mile 2
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. . 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 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. 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. . 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. 3
. 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: Distribution Declared Per Unit -------------------- Common Subordinated ------- ------------ 1999 Second quarter.................................... $0.4625 $0.4625 First quarter..................................... $0.45 $0.45 1998 Fourth quarter.................................... $0.193* $0.193* - -------- * 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 ($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." 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
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. 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
[CHART DEPICTING STRUCTURE OF THE PLAINS ENTITIES APPEARS HERE] 6
THE OFFERING Common units offered.......... 2,564,103 common units. Units outstanding after this 23,930,532 common units, including 1,307,190 offering...................... 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. 7
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
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. 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) 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 18,233 10,911 9,120 Other expense............... -- -- 410 410 Interest and other income... (1,435) (1,435) (768) (768) ---------- ---------- ---------- ---------- Pro forma net income........ $ 25,210 $ 29,086 $ 29,734 $ 31,525 ========== ========== ========== ========== 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........ 241,834 Partners' capital........... 354,056 Other Data: EBITDA(3)................... $ 74,146 $ 74,146 $ 39,826 $ 39,826 Maintenance capital expenditures(4)............ 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(5)..... 79,800 79,800 79,200 79,200 Pipeline: Tariff.................... 152,300 152,300 138,900 138,900 Margin(6)................. 49,200 49,200 55,400 55,400 ---------- ---------- ---------- ---------- Total pipeline........... 201,500 201,500 194,300 194,300 ========== ========== ========== ========== 9
- -------- (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) 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. (4) 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. (5) Represents total crude oil barrels delivered from the Cushing Terminal and the Ingleside Terminal. (6) Represents crude oil deliveries on the All American Pipeline. 10
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. . 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
. 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
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
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, 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 $0.6 million on the combined 2% general partner interest (including 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
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 % of the cash distributed 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 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
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
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 may 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. Additional common units would be issued as a result of: . the conversion of subordinated units; . the exercise of the underwriters' over-allotment option; 17
. 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, two of which have 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
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 19
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 20
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 whether the contamination extends outside the property boundaries. 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. 21
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 $200 million under the senior credit facility and approximately $80 million under the Plains Scurlock credit facility. 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 $25 million of aggregate unused borrowing capacity under the senior credit facility and approximately $20 million under the Plains Scurlock credit facility. 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 22
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 this allocable share of 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 23
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. 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. 24
USE OF PROCEEDS We estimate that the net 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 $ million. We anticipate using the net proceeds of the offering to: . repay approximately $ million under the Plains Scurlock credit facility; and . pay $ million 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 8, 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% (8.30% at September 8, 1999) and have a final maturity of May 2004. 25
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. As of June 30, 1999 ----------------------- Pro Forma Actual As Adjusted -------- ----------- (in thousands) Cash and cash equivalents...................... $ 12,133 $ 12,133 ======== ======== Long-term debt: Plains Scurlock credit facility.............. $ 89,350(1) $ 41,834(1)(2) Bank credit agreement........................ 200,000 200,000 -------- -------- Total long-term debt....................... 289,350 241,834 -------- -------- Partners' capital: Common unitholders........................... 259,184 306,195 Class B common unitholders................... 25,295 25,295 Subordinated unitholders..................... 20,546 20,546 General partner.............................. 1,515 2,020 -------- -------- Total partners' capital.................... 306,540 354,056 -------- -------- Total capitalization....................... $595,890 $595,890 ======== ======== - -------- (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 $238,000 associated with the prepayment of the Plains Scurlock credit facility. 26
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. 27
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, 28
. 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
(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 23,930,532 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
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. Yearly Distributions ------------------------------------------------------ Unitholders General Partner Total Quarterly --------------------- --------------------- ---------- Amount per Amount Amount Amount Target Distribution Unit (millions) Percentage (millions) Percentage (millions) ------------------- ------------ ---------- ---------- ---------- ---------- ---------- Minimum Quarterly Distribution........... $ 0.450 $ 61.1 98% $ 1.3 2% $ 62.4 First Target Distribution........... 0.495 67.2 85% 2.4 15% 69.6 Second Target Distribution........... 0.675 91.7 75% 10.5 25% 102.2 Thereafter.............. above 0.675 50% 50% 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 15,649,103 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
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
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
. 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
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 8, 1999, the last reported per unit sales price of the common units on the NYSE was $19.50. 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. Distribution Price Range Declared Per Unit ----------------- -------------------- Common Subordinated High Low Unit Unit -------- -------- ------- ------------ 1999 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* $0.193* - -------- * 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
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. 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) 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 18,233 10,911 9,120 Other expense......... -- -- 410 410 Interest and other income............... (1,435) (1,435) (768) (768) ---------- ---------- ---------- ---------- Pro forma net income.. $ 25,210 $ 29,086 $ 29,734 $ 31,525 ========== ========== ========== ========== 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.. 241,834 Partners' capital..... 354,056 Other Data: EBITDA(3)............. $ 74,146 $ 74,146 $ 39,826 $ 39,826 Maintenance capital expenditures(4)...... 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(5)....... 79,800 79,800 79,200 79,200 Pipeline: Tariff.............. 152,300 152,300 138,900 138,900 Margin(6)........... 49,200 49,200 55,400 55,400 ---------- ---------- ---------- ---------- Total pipeline..... 201,500 201,500 194,300 194,300 ========== ========== ========== ========== 36
- -------- (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) 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. (4) 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. (5) Represents total crude oil barrels delivered from the Cushing Terminal and the Ingleside Terminal. (6) Represents crude oil deliveries on the All American Pipeline. 37
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." 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) 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 38
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) 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 ====== ====== ====== ======= ======== ======= ======= ======== - ------- (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
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 the third quarter 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
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 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 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
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): Six Months Ended June 30, ------------------------------------ 1998 1998 1999 ------------- ----------- ---------- (Predecessor) (Pro Forma) 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 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
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 $22.0 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. Six Months Ended June 30, -------------------------------- 1998 1998 1999 ------------- ---------- ------ (Predecessor) (Pro Forma) (in thousands) Deliveries Average daily volumes (barrels): Within California.......................... -- 117 106 Outside California......................... -- 61 62 ------ ------ ------ Total.................................... -- 178 168 ====== ====== ====== 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
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. Year Ended December 31, ---------------------- 1997 1998 ---------- ---------- (pro forma, in thousands) 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 44
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. Year Ended December 31, -------------------------- 1997 1998 ------------ ------------ (pro forma, in thousands) Deliveries: Average daily volumes (barrels): Within California............................ 127 113 Outside California........................... 68 61 ------------ ------------ Total...................................... 195 174 ============ ============ 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
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: Year Ended December 31, ------------------------------ 1996 1997 1998 -------- -------- ---------- (in thousands) 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 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
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. 47
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. 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. 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. 48
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; . 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: . 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 $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 $279 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. 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. This distribution represents an increase of $.0125 per unit over the minimum quarterly distribution of $0.45 per unit. 49
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. 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. Financing activities for 1998 related to our initial public offering include: . proceeds of approximately $244.7 million; 50
. 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. 51
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: Key Applications, Equipment and Automated Systems Estimated Completion Date ------------------------------------ ------------------------- Third Party Developed Software September 1999 Computer Hardware and Equipment October 1999 Embedded Chip Systems October 1999 Financial Systems Applications October 1999 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 52
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: Change in Fair Fair Value from 10% At June 30, 1999 Value Adverse Price Change ---------------- ----- -------------------- (in millions) Crude oil futures contracts...................... $(2.3) $(2.0) Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal cash flows and the related weighted average interest rates by expected maturity dates 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. Expected Year of Maturity --------------------------------------------------------- Fair 1999 2000 2001 2002 2003 Thereafter Total Value ----- ----- ---- ---- ---- ---------- ------ ------ (dollars in millions) 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% 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 the $175 million notional amount. 53
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 transporters, 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. 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 ratably to Midwest refineries. . 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 ratable 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. 54
. 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 and increase the utilization of our pipeline assets. . 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 55
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 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. . 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 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 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. 56
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 also connected to the All American Pipeline at Wink and the Spraberry Pipeline System at Midland. . 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 57
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 58
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 the California margin activities. For the six months ended June 30, 1999, these activities accounted for approximately 84% 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. 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 59
December 31, 1998, the tariffs averaged $1.41 per barrel for deliveries to connecting pipelines in California and $2.96 per barrel for deliveries to connecting pipelines in West Texas. The agreements do not require these owners to transport a minimum volume. The producers from the Point Arguello field who do not have contracts with 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. Six Months Ended Year Ended December 31, June 30, --------------------------------------- --------- 1991 1992 1993 1994 1995 1996 1997 1998 1998 1999 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- (barrels in thousands) 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 === === === === === === === === === === 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 field for 1999 and 2000 will generally approximate 60,000 to 65,000 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 60
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. Four Months Ended Year Ended December 31, April 30, -------------------------------------------- --------- 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- ---- ---- ---- ---- --------- (barrels in thousands) 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 - -------- (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, West Coast Heavy crude is blended with Domestic Sweet Crude to increase the gravity (the blend is commonly referred to as West Coast Sour), permitting delivery into third- party pipelines that can transport the crude to the Cushing Interchange 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. 61
The following table sets forth All American Pipeline average deliveries per day within and outside California. Six Months Ended Year Ended December 31, June 30, ------------------------ --------- 1994 1995 1996 1997 1998 1998 1999 ---- ---- ---- ---- ---- ---- ---- (barrels in thousands) 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 === === === === === === === 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. Six Months Ended Year Ended December 31, June 30, ------------------------ --------- 1994 1995 1996 1997 1998 1998 1999 ---- ---- ---- ---- ---- ---- ---- (barrels in thousands) Total average daily volumes.................. 54 50 67 91 85 91 99 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, which, in aggregate, 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 62
major segments are bi-directional and allow us to move crude oil between three of the major trading locations in West Texas. Lease volumes gathered into the system are approximately 50,000 barrels per day with production from Chevron USA accounting for approximately half of that volume. 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, PennzEnergy, Anadarko, Altura, Bass, and Fina. Volumes from connecting carriers, including Exxon, Phillips and Unocal, average approximately 45,000 barrels per day. Currently, truck injection stations are limited and provide less than 1,000 barrels per day. The West Texas Gathering System also includes approximately 2.9 million barrels of tank capacity located along the pipeline system. 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 and is currently operating near capacity. 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 6 to 10 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 3 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. 63
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 24,000 barrels per day of foreign 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. 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. 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 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; 64
. 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. 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] 65
The following table outlines our terminal locations, capacities, tanks and modes of receipt and deliveries: Shell Number Mode of Facility Capacity of Tanks Mode of Receipt Delivery -------- --------- -------- --------------- -------- (Barrels) 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 ========= === - -------- (1) Does not include approximately 5.5 million barrels of 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 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. Six Months Ended Year Ended December 31, June 30, ------------------------- ---------- 1994 1995 1996 1997 1998 1998 1999 ---- ---- ---- ---- ----- ---- ----- (barrels in thousands) 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 === === === === ===== === ===== 66
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. Six Months Year Ended December Ended 31, June 30, ------------------- --------- 1995 1996 1997 1998 1998 1999 ---- ---- ---- ---- ---- ---- (barrels in thousands) 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 === === === === === === - -------- (1) Includes volumes from Scurlock Permian since May 1, 1999. Crude Oil Purchases. In a typical producer's operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the crude oil is treated to remove water, sand and other contaminants and is then moved into the producer's on-site storage tanks. When the tank is full, the producer contacts our field personnel to purchase and transport the crude oil to market. We utilize our truck fleet and gathering pipelines and third-party pipelines, trucks and barges to transport the crude oil to market. We own or lease approximately 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. 67
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 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 68
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. 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 69
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. 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 70
. 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 recent proceeding involving Lakehead Pipe Line Company, Limited Partnership (Opinion No. 397), FERC concluded that there should not be a corporate income tax allowance built into a petroleum pipeline's rates to reflect income attributable to noncorporate partners since noncorporate partners, unlike corporate partners, do not pay a corporate income tax. This result comports with the principle that, although a regulated entity is entitled to an allowance to cover its incurred costs, including income taxes, there should not be an element included in the cost of service to cover costs not incurred. Opinion No. 397 was affirmed on rehearing in May 1996. Appeals of the Lakehead opinions were taken, but the parties to the Lakehead proceeding subsequently settled the case, with the result that appellate review of the tax and other issues never took place. There is also pending at the FERC a proceeding involving another publicly traded limited partnership engaged in the common carrier transportation of crude oil (the "Santa Fe Proceeding") in which the FERC could further limit its current position related to the tax allowance permitted in the rates of publicly traded partnerships, as well as possibly alter the FERC's current application of the FERC oil pipeline ratemaking methodology. On September 25, 1997, the administrative law judge in the Santa Fe Proceeding issued an initial decision addressing various aspects of the tax allowance issue as it affects publicly traded partnerships, as well as various technical issues involving the application of the FERC oil pipeline ratemaking methodology. The administrative law judge's initial decision in the Santa Fe Proceeding is currently pending review by the FERC. In such review, it is possible that the FERC could alter its current rulings on the tax allowance issue or on the application of the FERC oil pipeline ratemaking methodology. The FERC generally has not investigated rates, such as those currently charged by 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 71
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 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 72
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. 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 73
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 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 have proposed a voluntary state-administered remediation of the contamination on the property to determine whether the contamination extends outside the property boundaries. If our plan is disapproved, a government mandated remediation of the spill could require expenditures of approximately $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. 74
Title to Properties Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property and in some instances such rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. All of the pump stations are located on property owned in fee or property under long-term leases. In certain states and under certain circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines. Some of the leases, easements, rights-of-way, permits and licenses transferred to us, upon our formation in 1998 and in connection with acquisitions we have made since that time, required the consent of the grantor to transfer such rights, which in certain instances is a governmental entity. 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. 75
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. Name Age Position with General Partner ---- --- ----------------------------- 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 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 76
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 Senior 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, 77
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. 78
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 79
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. 80
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. 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 - ------------------------ --------- ---------- --------- ------------- ------------ ------------- ---------- 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) - -------- (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. 81
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. Shares Beneficially Percent Name of Beneficial Owner Owned(1) of Class ------------------------ ------------ -------- 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% - -------- (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. 82
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Rights of the General Partner After this offering, the general partner and its affiliates will own 6,974,239 common units, 1,307,190 Class B 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 6,974,239 common units, 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 83
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. 84
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; 85
. 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 86
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. 87
. 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 Fiduciary duties are generally considered to standards................. 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. 88
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." 89
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 its 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; 90
(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. 91
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 92
(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. 93
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." 94
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. 95
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 they 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. 96
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; 97
(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. 98
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 99
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. 100
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: 101
(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, 102
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, 103
(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. 104
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." 105
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." 106
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 days from the date of this prospectus, they will not, without the prior written consent of , 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 or the redemption of the subordinated units in the event the over-allotment option is exercised. 107
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 in 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"); 108
(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 109
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 110
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 % 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 111
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. 112
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." The effect of these allocations to a unitholder will be essentially the same as if the tax basis of the Contributed Property were equal to its fair market value at the time of contribution. 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: 113
. 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, 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 of which is not 114
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 property contributed and the tax basis established for that property will be borne by the contributors of that property. 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 115
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 116
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 117
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 118
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. 119
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; 120
(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. 121
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. 122
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. 123
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. Number of Common Name Units ---- ------ ------ Total............................................................... ====== 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, for whom are acting as representatives, 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 representatives may change the public offering price and the other selling terms. The representatives have advised us that the underwriters 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 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 days from the date of this prospectus, they will not, without the prior written consent of , 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. 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. Paid by Us ----------------- No Full Exercise Exercise -------- -------- Per common unit............................................ $ Total.................................................... $ 124
In connection with the offering, , 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 , 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 that our portion of the total expenses of this offering will be $ . 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 representatives have performed certain investment banking and advisory services for us from time to time for which they have received customary fees and expenses. The representatives may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. We, 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. 125
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 , 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. 126
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. 127
INDEX TO FINANCIAL STATEMENTS Page ---- 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 F-1
INDEX TO FINANCIAL STATEMENTS--(Continued) Page ---- 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 F-2
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 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., a limited partnership of PAA, 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 2,564,103 limited partner units at a price of $19.50 per unit expected to raise approximately $50 million in gross proceeds ($47.3 million, net after $2.8 million in underwriters' discounts and commissions and offering expenses). 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
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES PRO FORMA CONSOLIDATED BALANCE SHEET (unaudited) June 30, 1999 (in thousands, except unit data) Historical -------------- Plains All American Offering Pro Forma ASSETS Pipeline, L.P. Adjustments As Adjusted ------ -------------- ----------- ----------- CURRENT ASSETS Cash and cash equivalents.......... $ 12,133 $47,250 R $ 12,133 (47,250) S 505 R (505) S 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 ========== ======= ========== LIABILITIES AND PARTNERS' CAPITAL --------------------------------- 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 (47,516) S 241,834 Other.............................. 1,264 -- 1,264 ---------- ------- ---------- Total liabilities................ 700,246 (47,516) 652,730 ---------- ------- ---------- PARTNERS' CAPITAL Common unitholders (20,059,239 units outstanding, 22,623,342 pro forma)........................ 259,184 47,011 R 306,195 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.................... 1,515 505 R 2,020 ---------- ------- ---------- 306,540 47,516 354,056 ---------- ------- ---------- $1,006,786 $ -- $1,006,786 ========== ======= ========== See notes to pro forma consolidated financial statements. F-4
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) 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 -------------- ------------ ----------- ---------- ----------- ----------- REVENUES................ $1,318,284 $775,331 $ (493) A $1,705,586 $ -- $1,705,586 (38,535) G (476,743) H 127,742 L COST OF SALES AND OPERATIONS............. 1,272,244 763,511 (94) A 1,649,327 -- 1,649,327 (759) E (496) F (38,535) G (474,803) H (664) I 2,052 J 126,871 L TAXES OTHER THAN INCOME TAXES.................. -- 757 (928) H -- -- -- 171 L 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) A 16,791 -- 16,791 (341) E (313) I 1,985 L Depreciation and amortization........... 6,671 2,952 (59) A 8,680 -- 8,680 2,009 C (3,783) D 890 L ---------- -------- -------- ---------- ------- ---------- 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 B 10,911 (1,791)S 9,120 Other expense........... 410 -- -- 410 410 Interest and other income................. (287) -- 547 A (768) -- (768) (1,012) H (16) L ---------- -------- -------- ---------- ------- ---------- NET INCOME.............. $ 23,386 $ 10,169 $ (3,821) $ 29,734 $ 1,791 $ 31,525 ========== ======== ======== ========== ======= ========== 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 33,960 ========== ========== ========== See notes to pro forma consolidated financial statements. F-5
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) 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) REVENUES........... $953,244 $176,445 $3,773,536 $374,654 $ (2,502) A $2,817,051 $ -- $2,817,051 (103,242) G (2,419,594) H 62,995 L 1,515 P COST OF SALES AND OPERATIONS........ 922,263 168,946 3,742,276 344,538 (1,451) A 2,710,157 -- 2,710,157 (3,254) E (1,460) F (103,242) G (2,416,155) H (2,781) I 515 J 59,962 L TAXES OTHER THAN INCOME TAXES...... -- -- 2,653 -- (2,653) H -- -- -- 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) A 34,183 -- 34,183 (1,023) E (1,743) I 151 L Depreciation and amortization...... 4,179 1,192 11,136 6,808 (248) A 17,328 -- 17,328 11,957 C (18,721) D 1,025 L -------- -------- ---------- -------- ----------- ---------- ------ ---------- 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 B 22,109 (3,876) S 18,233 12,224 N -- (9,096) Q Related party interest expense.......... 2,768 -- -- 21,929 (21,929) M -- -- -- (2,768) Q Interest and other income..... (572) (12) -- -- (65) A (1,435) -- (1,435) (786) H -------- -------- ---------- -------- ----------- ---------- ------ ---------- Net income (loss) before provision in lieu of income taxes..... 11,588 4,177 (23,576) 326 32,695 25,210 3,876 29,086 Provision in lieu of income taxes............ 4,563 -- -- 84 419 L -- -- -- (5,066) O -------- -------- ---------- -------- ----------- ---------- ------ ---------- NET INCOME (LOSS).. $ 7,025 $ 4,177 $ (23,576) $ 242 $ 37,342 $ 25,210 $3,876 $ 29,086 ======== ======== ========== ======== =========== ========== ====== ========== 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 33,960 ======== ======== ========== ========== See notes to pro forma consolidated financial statements. F-6
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 Acquisitions and Initial Public Offering A. Reflects the elimination of revenues and expenses associated with certain Scurlock assets that were not purchased by PAA. B. 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. C. 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. D. Reflects the elimination of historical Scurlock and Wingfoot depreciation and amortization expense. E. 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. F. 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. G. Reflects the elimination of historical sales and purchases between Scurlock and PAA. H. 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. 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. F-7
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. 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. M. 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. N. 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). O. Reflects the elimination of the historical income tax provision as income taxes will be borne by the partners and not the Partnership. P. 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. 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. Offering R. Reflects the estimated net proceeds to the Partnership of $47.3 million from the issuance and sale of 2.6 million Common Units at an offering price of $19.50 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. S. Reflects the repayment of approximately $47.5 million of debt outstanding under Plains Scurlock's credit facility at June 30, 1999 and the related reduction in interest expense for the six months ended June 30, 1999 and the year ended December 31, 1998. 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
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data) December 31, June 30, 1998 1999 ------------ ----------- (unaudited) ASSETS ------ 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 ======== ========== LIABILITIES AND PARTNERS' CAPITAL ------------------------- 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 ======== ========== See notes to consolidated and combined financial statements. F-9
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF INCOME (unaudited) (in thousands, except per unit data) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ------------------------- 1998 1999 1998 1999 ------------- -------- ------------- ----------- (Predecessor) (Predecessor) 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 ======== ======== ======== =========== See notes to consolidated and combined financial statements. F-10
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (unaudited) (in thousands) Six Months Ended June 30, ---------------------- 1998 1999 ------------- -------- (Predecessor) 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 ======= ======== See notes to consolidated and combined financial statements. F-11
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"). For further information, refer to the consolidated and combined financial statements and notes thereto included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 1998, filed with the 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
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: (in thousands) 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 ======== F-13
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. Six Months Ended June 30, --------------------- 1998 1999 ---------- ---------- (in thousands) 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 ========== ========== 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
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: Marketing, Gathering, Terminalling (In thousands) Pipeline & Storage Total - -------------- -------- ------------ ---------- 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 - -------- (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
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
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED BALANCE SHEETS (in thousands, except unit data) December 31, ---------------------- 1997 1998 ------------- -------- (Predecessor) ASSETS ------ 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 ======== ======== LIABILITIES AND EQUITY ---------------------- 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 ======== ======== See notes to consolidated and combined financial statements. F-17
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF INCOME (in thousands, except per unit and unit data) January 1, November 23, Year Ended December 31, 1998 To 1998 To --------------------------- November 22, December 31, 1996 1997 1998 1998 ------------- ------------- ------------- ------------ (Predecessor) (Predecessor) (Predecessor) 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 ========== ========== ========== ========== See notes to consolidated and combined financial statements. F-18
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (in thousands) January 1, November 23, Year Ended December 31, 1998 To 1998 To --------------------------- November 22, December 31, 1996 1997 1998 1998 ------------- ------------- ------------- ------------ (Predecessor) (Predecessor) (Predecessor) 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 ======= ======= ======== ======== See notes to consolidated and combined financial statements. F-19
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998 (in thousands) Total Subordinated General Partners' Common Units Units Partner Equity --------------- ---------------- ------- --------- Units Amount Units Amount Amount Amount ------ -------- ------ --------- ------- --------- Issuance of units to public................. 13,085 $241,690 -- $ -- $ -- $ 241,690 Contribution of assets and debt assumed....... 6,974 108,253 10,030 155,680 9,533 273,466 Distribution at time of formation.............. -- (95,675) (137,590) (8,425) (241,690) Net income for the period from November 23, 1998 to December 31, 1998............... -- 2,729 -- 1,364 84 4,177 ------ -------- ------ --------- ------- --------- Balance at December 31, 1998................... 20,059 $256,997 10,030 $ 19,454 $ 1,192 $ 277,643 ====== ======== ====== ========= ======= ========= See notes to consolidated and combined financial statements. F-20
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
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
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 if forces a barrel out at another location. The Partnership owns approximately 5.0 million barrels of crude oil that is used to maintain the All American Pipeline's linefill requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated and combined statements of cash flows. The following is a summary of the components of property and equipment: December 31, ----------------- 1997 1998 ------- -------- (in thousands) 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 ======= ======== Impairment of Long-Lived Assets Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with Statement of Financial Accounting Standards No. 121. Fair value is generally determined from estimated discounted future net cash flows. Other Assets Other assets consist of the following: December 31, --------------- 1997 1998 ------ ------- (in thousands) 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 ====== ======= 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
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
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
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. Year January 1, Ended 1998 to December 31, November 22, 1997 1998 ------------ ------------ (in thousands) 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 ========== ========== The pro forma net loss for the year ended December 31, 1997, includes a non- cash impairment charge of $64.2 million related to the writedown of pipeline assets and linefill by Wingfoot in connection with the sale of the Celeron Companies by Goodyear to the Predecessor. Based on the Predecessor's purchase price allocation to property and equipment and pipeline linefill, an impairment charge would not have been required had the Predecessor actually acquired the Celeron Companies effective January 1, 1997. Excluding this impairment charge, the Predecessor's pro forma net income for 1997 would have been $23.4 million ($1.35 per basic and diluted limited partner unit). The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16 as follows (in thousands): Crude oil pipeline, gathering and terminal assets............... $392,528 Other assets (debt issue costs)................................. 6,138 Net working capital items (excluding cash received of $7,481)... 1,498 -------- Cash paid....................................................... $400,164 ======== Financing for the acquisition was provided through (i) a $325 million, limited recourse bank facility and (ii) an approximate $114 million capital contribution by Plains Resources. Actual borrowings at closing were $300 million. Note 3--Credit Facilities Bank Credit Agreement. The Partnership has a $225 million Bank Credit Agreement which consists of the $175 million Term Loan Facility and the $50 million Revolving Credit Facility. The $50 million Revolving Credit Facility is used for capital improvements and working capital and general business purposes and contains a $10 million sublimit for letters of credit issued for general corporate purposes. The Bank Credit Agreement is collateralized by a lien on substantially all of the assets of the Partnership. The Term Loan Facility bears interest at the Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. The Partnership has two ten year interest rate swaps (subject to cancellation by the counterparty after seven years) aggregating $175 million notional principal amount which fix the LIBOR portion of the interest rate (not including the applicable margin) at a weighted average rate of approximately 5.24%. Borrowings under the Revolving Credit Facility bear interest at the Partnership's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. The Partnership incurs a commitment fee on the unused portion of the Revolving Credit Facility and, with respect to each issued letter of credit, an issuance fee. F-26
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
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
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
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: December 31, 1998 ---------------- Carrying Fair Amount Value -------- ------- (in thousands) Unrealized loss on interest rate swaps.................. $ -- $(2,164) F-30
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
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): 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 ======== 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
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
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
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. Marketing, Gathering, Terminalling Pipeline & Storage Total -------- ------------ ---------- (in thousands) 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 - -------- (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
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: Year Ended January 1, December 31, 1998 to ------------------- November 22, 1996 1997 1998 ---- -------------- ------------ (in thousands) Federal Current................................ $ 1 $ 38 $ 455 Deferred............................... 706 1,131 3,390 State Current................................ 19 99 -- Deferred............................... -- -- 718 ---- ------ ------ Total.................................... $726 $1,268 $4,563 ==== ====== ====== 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: Year Ended January 1, December 31, 1998 to ------------------- November 22, 1996 1997 1998 ---- -------------- ------------ (in thousands) 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 ==== ====== ====== The Plains Midstream Subsidiaries' payable in lieu of deferred taxes at December 31, 1997 results from differences in depreciation methods used for financial purposes and for tax purposes. Note 13--Combined Equity The following is a reconciliation of the combined equity balance of the Plains Midstream Subsidiaries (in thousands): Balance at December 31, 1995.................................. $ 2,613 Net income for the year....................................... 1,222 -------- Balance at December 31, 1996.................................. 3,835 Net income for the year....................................... 2,140 -------- Balance at December 31, 1997.................................. 5,975 Capital contribution in connection with the acquisition of the Celeron Companies............................................ 113,700 Dividend to Plains Resources.................................. (3,557) Net income for the period from January 1, 1998, to November 22, 1998..................................................... 7,025 -------- $123,143 ======== F-36
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
SCURLOCK PERMIAN BUSINESSES BALANCE SHEETS (in thousands) December 31, March 31, 1998 1999 ------------ ----------- (unaudited) ASSETS ------ 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 ======== ======== LIABILITIES AND PARENT COMPANY INVESTMENT ----------------------------------------- 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 ======== ======== The accompanying notes are an integral part of these financial statements. F-38
SCURLOCK PERMIAN BUSINESSES STATEMENTS OF OPERATIONS (unaudited) (in thousands) Three Months Ended March 31, -------------------- 1998 1999 --------- --------- 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 ========= ========= The accompanying notes are an integral part of these financial statements. F-39
SCURLOCK PERMIAN BUSINESSES STATEMENTS OF CASH FLOWS (unaudited) (in thousands) Three Months Ended March 31, -------------------- 1998 1999 --------- --------- 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 ========= ========= The accompanying notes are an integral part of these financial statements. F-40
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 March 31, 1999 and December 31, 1998, 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
SCURLOCK PERMIAN BUSINESSES NOTES TO INTERIM FINANCIAL STATEMENTS (unaudited)--(Continued) Inventories consist of the following: December 31, March 31, 1998 1999 ------------ --------- (Thousands) 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 ======= ======= 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
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
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
SCURLOCK PERMIAN BUSINESSES STATEMENT OF OPERATIONS (dollars in thousands) (Predecessor) Year Ended ------------------------- (Company) December 31, December 31, Year Ended 1996 1997 December 31, 1998 ------------ ------------ ----------------- 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) ========== ========== ========== The accompanying notes are an integral part of these financial statements. F-45
SCURLOCK PERMIAN BUSINESSES BALANCE SHEET (dollars in thousands) (Predecessor) (Company) December 31, December 31, 1997 1998 ------------- ------------ ASSETS ------ 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 ======== ======== LIABILITIES ----------- 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 ======== ======== The accompanying notes are an integral part of these financial statements. F-46
SCURLOCK PERMIAN BUSINESSES STATEMENT OF CASH FLOWS (dollars in thousands) (Predecessor) Year Ended (Company) ------------------------ Year Ended December 31, December 31, December 31, 1996 1997 1998 ------------ ------------ ------------ 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 ======== ========= ======== See Note K for supplemental cash flow information. The accompanying notes are an integral part of these financial statements. F-47
SCURLOCK PERMIAN BUSINESSES STATEMENT OF CHANGES IN PARENT COMPANY INVESTMENT (dollars in thousands) (Predecessor) ------------- 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 ======= (Company) --------- 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 ======== The accompanying notes are an integral part of these financial statements. F-48
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 1997 and 1996. 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
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
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
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. (Predecessor) Year Ended ------------------------- (Company) Year Ended December 31, December 31, December 31, 1996 1997 1998 ------------ ------------ ------------ (Thousands) (Thousands) Matching crude oil buy/sell transactions settled in cash.......... $2,665,054 $2,851,069 $2,179,843 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
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: (Predecessor) Year Ended ------------------------- December 31, December 31, 1996 1997 ------------ ------------ (Thousands) (Thousands) 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) ====== ======= 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: (Predecessor) ----------------------- 1996 1997 ----------- ----------- (Thousands) (Thousands) 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) ====== ======== F-53
SCURLOCK PERMIAN BUSINESSES NOTES TO FINANCIAL STATEMENTS--(Continued) NOTE H--INVENTORIES Inventories consist of the following: (Predecessor) (Company) December 31, December 31, 1997 1998 ------------- ------------ (Thousands) (Thousands) 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 ======= ======= 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 (Predecessor) (Company) December 31, December 31, 1997 1998 ------------- ------------ (Thousands) (Thousands) Equity method investment......................................................................... $ 981 $2,466 Cost method investment........................................................................... 633 -- Other............................................................................................ -- 21 ------ ------ $1,614 $2,487 ====== ====== F-54
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: (Company) (Predecessor) Year Ended Year Ended ------------------------- ------------ December 31, December 31, December 31, 1996 1997 1998 ------------ ------------ ------------ (Thousands) (Thousands) Income data: Revenues............................ $3,039 $2,474 $2,110 Operating income.................... 252 135 66 Net income.......................... 252 135 66 December 31, December 31, 1997 1998 ------------ ------------ (Thousands) (Thousands) Balance sheet data: Current assets................................... $ 28 $ 44 Non-current assets............................... 1,961 1,835 Current liabilities.............................. 28 44 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 (Predecessor) (Company) December 31, December 31, 1997 1998 ------------- ------------ (Thousands) (Thousands) 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 ======== ======== NOTE K--SUPPLEMENTAL CASH FLOW INFORMATION (Predecessor) Year Ended (Company) ------------------------- Year Ended December 31, December 31, December 31, 1996 1997 1998 ------------ ------------ ------------ (Thousands) (Thousands) 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 F-55
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: Operating Leases ----------- (Thousands) 1999............................................................. $ 2,073 2000............................................................. 2,071 2001............................................................. 2,073 2002............................................................. 524 2003............................................................. 384 Later Years...................................................... 4,811 ------- Total minimum lease payments................................... $11,936 ======= 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: Aggregate Recorded Contract Deferred Values Gain or (Loss) (a) -------------- --------- (Thousands) (Predecessor) December 31, 1997: Exchange-traded commodity futures................. $(2,817) $29,157 (Company) December 31, 1998: Exchange-traded commodity futures................. $ 191 $ 8,964 - -------- (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
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
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
WINGFOOT VENTURES SEVEN, INC. CONSOLIDATED BALANCE SHEETS (in thousands, except share data) December 31, June 30, 1997 1998 ------------ ----------- (unaudited) ASSETS ------ 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 =========== =========== LIABILITIES AND STOCKHOLDER'S EQUITY ------------------------------------ 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 =========== =========== See notes to consolidated financial statements. F-59
WINGFOOT VENTURES SEVEN, INC. CONSOLIDATED STATEMENTS OF INCOME (unaudited) (in thousands) Six Months Ended June 30, ----------------- 1997 1998 -------- -------- 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 ======== ======== See notes to consolidated financial statements. F-60
WINGFOOT VENTURES SEVEN, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands) Six Months Ended June 30, ------------------ 1997 1998 -------- -------- 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 ======== ======== See notes to consolidated financial statements. F-61
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
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
WINGFOOT VENTURES SEVEN, INC. (A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY) CONSOLIDATED BALANCE SHEETS (dollars in thousands) December 31, ------------------------ 1996 1997 ----------- ----------- ASSETS ------ 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 =========== =========== LIABILITIES AND STOCKHOLDER'S EQUITY ------------------------------------ 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 =========== =========== The accompanying notes are an integral part of this statement. F-64
WINGFOOT VENTURES SEVEN, INC. (A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY) CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT (dollars in thousands) For the Years Ended December 31, ----------------------------------- 1995 1996 1997 --------- ----------- ----------- 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) ========= =========== =========== The accompanying notes are an integral part of this statement. F-65
WINGFOOT VENTURES SEVEN, INC. (A WHOLLY-OWNED SUBSIDIARY OF THE GOODYEAR TIRE & RUBBER COMPANY) CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) For the Years Ended December 31, ----------------------------- 1995 1996 1997 -------- --------- -------- 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 ======== ========= ======== The accompanying notes are an integral part of this statement. F-66
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
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
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: December 31, ------------------------ 1996 1997 ----------- ----------- Oil pipeline facilities......................... $ 1,549,178 $ 1,550,391 Less: accumulated depreciation.................. (1,128,556) (1,198,683) ----------- ----------- $ 420,622 $ 351,708 =========== =========== 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
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. December 31, ----------------- 1996 1997 -------- -------- 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 ======== ======== 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
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
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: For the Year Ended December 31, ---------------- 1995 1996 1997 ---- ---- ---- Service cost............................................ $ 63 $ 71 $ 86 Interest cost........................................... 185 183 186 Net amortization........................................ (23) (9) (10) ---- ---- ---- Net periodic postretirement benefit cost................ $225 $245 $262 ==== ==== ==== The following table sets forth the funded status and amounts recognized on Wingfoot's Consolidated Balance Sheet: December 31, ---------------- 1996 1997 ------- ------- 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) ======= ======= 1995 1996 1997 ---- ---- ---- The assumptions used were: Discount rate......................................... 7.75% 7.75% 7.75% Rate of increase in compensation levels............... 4.50 4.50 4.50 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
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: For the Year Ended December 31, ----------------------- 1995 1996 1997 ----- ------- ------- 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) ===== ======= ======= 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. December 31, ---------------- 1996 1997 ------- ------- 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 ======= ======= 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
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: For the Year End December 31, ------------------- 1995 1996 1997 ----- ----- ----- Interest cost........................................ $ 416 $ 409 $ 375 Amortization of gain................................. (28) (2) (11) ----- ----- ----- Net periodic pension cost............................ $ 388 $ 407 $ 364 ===== ===== ===== The funded status of these plans consisted of: December 31, ---------------- 1996 1997 ------- ------- 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) ======= ======= 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: 1995 1996 1997 ----- ----- ----- 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% 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
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: December 31, ---------------------- 1995 1996 1997 ------- ------ ----- 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 ======= ====== ===== 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
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: Operating Year Ending December 31, Leases ------------------------ --------- 1998.......................................................... $ 924 1999.......................................................... 893 2000.......................................................... 878 2001.......................................................... 874 2002.......................................................... 875 Thereafter.................................................... 3,273 ------ $7,717 ====== 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
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
PLAINS ALL AMERICAN INC. CONSOLIDATED BALANCE SHEET (in thousands, except share data) December 31, 1998 ------------ ASSETS CURRENT ASSETS Cash and cash equivalents........................................ $ 6,408 Accounts receivable.............................................. 116,328 Due from affiliates.............................................. 1,655 Inventory ....................................................... 37,711 Prepaid expenses and other....................................... 4,327 -------- 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 ======== See notes to consolidated balance sheet. F-78
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
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
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: December 31, 1998 -------------- (in thousands) 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 ======== Impairment of Long-Lived Assets Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with Statement of Financial Accounting Standards No. 121. Fair value is generally determined from estimated discounted future net cash flows. Other Assets Other assets consist of the following: December 31, 1998 -------------- (in thousands) 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 ======= 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
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
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): Crude oil pipeline, gathering and terminal assets................ $392,528 Other assets (debt issue costs).................................. 6,138 Net working capital items (excluding cash received of $7,481).... 1,498 -------- Cash paid........................................................ $400,164 ======== Financing for the acquisition was provided through (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
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
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
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
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: December 31, 1998 ---------------- Carrying Fair Amount Value -------- ------- (in thousands) Unrealized loss on interest rate swaps.................. $ -- $(2,164) 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
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
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
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. Marketing, Gathering, Terminalling (In thousands) Pipeline & Storage Total - ------------------------------------------------------------------------------- Year Ended December 31, 1998 Capital Expenditures......................... $393,731 $7,212 $400,943 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
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: (in thousands) 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 ======== 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
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
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
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 (other than the common units sold to the underwriters upon the exercise of their over-allotment option) 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
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
(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
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: Securities and Exchange Commission registration fee................. $15,985 NASD filing fee..................................................... * NYSE listing fee.................................................... * Printing and engraving expenses..................................... * Legal fees and expenses............................................. * Accounting fees and expenses........................................ * Transfer agent and registrar fees................................... * Miscellaneous....................................................... * ------- TOTAL............................................................. $ * ======= - -------- *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 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: 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) II-1
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) II-2
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) - -------- *Filed herewith **To be filed by amendment (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
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
SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on September 10, 1999. PLAINS ALL AMERICAN PIPELINE, L.P. By: Plains All American Inc.,its general partner /s/ Greg L. Armstrong By___________________________________ Name: Greg L. Armstrong Title: Chairman of the Board and Chief Executive Officer POWER OF ATTORNEY Each person whose signature appears below appoints Phillip D. Kramer and Michael R. Patterson, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462 (b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof. 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. Signature Title Date --------- ----- ---- /s/ Greg L. Armstrong Chairman of the Board, September 10, 1999 ____________________________________ Chief Executive Officer and Greg L. Armstrong Director (Principal Executive Officer) /s/ Harry N. Pefanis President, Chief Operating September 10, 1999 ____________________________________ Officer and Director Harry N. Pefanis /s/ Phillip D. Kramer Executive Vice President and September 10, 1999 ____________________________________ Chief Financial Officer Phillip D. Kramer (Principal Financial Officer) /s/ Cynthia A. Feeback Treasurer (Principal September 10, 1999 ____________________________________ Accounting Officer) Cynthia A. Feeback /s/ Everardo Goyanes Director September 10, 1999 ____________________________________ Everardo Goyanes /s/ Robert V. Sinnott Director September 10, 1999 ____________________________________ Robert V. Sinnott /s/ Arthur L. Smith Director September 10, 1999 ____________________________________ Arthur L. Smith II-5
EXHIBIT 10.20 Payment on Vesting TRANSACTION GRANT AGREEMENT September 9, 1999 Greg L. Armstrong 500 Dallas St. Suite 700 Houston, TX 77002 Re: Grant of MLP Phantom Units Dear Mr. Armstrong: I am pleased to inform you that the Company hereby grants to you 75,000 MLP Phantom Units, with an equal number of distribution equivalent rights ("DERs"). A MLP Phantom Unit is a right to receive, upon vesting as provided below, a Common Unit of Plains All American Pipeline, L.P. (the "MLP") and a DER is a right to receive an amount in cash from the Company equal to the distributions made by MLP with respect to a Common Unit during the period ending on the earlier of December 31, 2003 or the date the tandem MLP Phantom Unit is paid to you or forfeited. The terms of this grant are set forth below. 1. Subject to the further vesting provisions below, the MLP Phantom Units will become vested (nonforfeitable) as follows: (a) on December 31, 1999, (i) 1/9th of the total number of MLP Phantom Units granted you (the "Total Units") shall become vested if the Operating Surplus of the MLP for 1999 equals or exceeds the sum of the Minimum Quarterly Distributions ("MQDs") for such year with respect to the Common Units and the related General Partner Interest, and (ii) an additional 2/9ths of the Total Units shall become vested if the Operating Surplus of the MLP for 1999 equals or exceeds the sum of the MQDs with respect to the Common Units and Subordinated Units and the related General Partner Interest for 1999; (b) on December 31, 2000, (i) an additional 1/9th of the Total Units shall become vested if the Operating Surplus of the MLP for 2000 equals or exceeds the sum of the MQDs for such year with respect to the Common Units and the related General Partner Interest, and (ii) an additional 2/9ths of the Total Units shall become vested if the Operating Surplus of the
MLP for 2000 equals or exceeds the sum of the MQDs with respect to the Common Units and Subordinated Units and the related General Partner Interest for 2000; (c) on December 31, 2001, (i) an additional 1/9th of the Total Units shall become vested if the Operating Surplus of the MLP for 2001 equals or exceeds the sum of the MQDs for such year with respect to the Common Units and the related General Partner Interest, and (ii) an additional 2/9ths of the Total Units shall become vested if the Operating Surplus of the MLP for 2001 equals or exceeds the sum of the MQDs with respect to the Common Units and Subordinated Units and the related General Partner Interest for 2001; (d) the MLP Phantom Units that would have vested at the end of 1999, 2000, or 2001 had the MQDs been paid such year(s) shall become vested on the date any arrearages in MQDs for such year(s) are paid; (e) any MLP Phantom Units which have not vested pursuant subparagraphs (a)(ii), (b)(ii), or (c)(ii) above as of December 31, 2001 shall become vested upon, and in the same proportion as, the conversion of Subordinated Units to Common Units; and (f) if the Company is removed as the General Partner of the MLP other than for Cause prior to January 1, 2002, the Phantom Units shall become vested on the date of such removal. The terms Operating Surplus, Minimum Quarterly Distribution, General Partner Interest, and Cause shall have their respective meanings as set forth in the Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P.; provided, however, Operating Surplus included in clause (a)(i) of the definition of Operating Surplus shall be excluded for purposes of this Agreement. 2. In the event of your termination of employment with the Company and its affiliates for any reason other than your death or a disability that entitles you to benefits under the long-term disability plan of the Company ("Disability"), all of your MLP Phantom Units not then vested shall automatically be forfeited unpaid as of your date of termination. 3. In the event of your termination of employment with the Company and its affiliates due to your death or Disability, your MLP Phantom Units shall continue to vest as provided in paragraph 1 above. 4. Vested MLP Phantom Units will be paid by the Company as soon as reasonably practicable following each vesting date. 5. DERs with respect to the MLP Phantom Units will be credited (without interest) to a Company ledger account (the "DER Account") for your benefit and upon payment of any vested MLP Phantom Units, the amounts then credited to your DER Account with respect to such vested units will be paid to you in cash. Any amount credited to the DER Account with respect to unvested MLP Phantom Units will be forfeited if and whenever such MLP Phantom Units are forfeited.
6. The Company will withhold any taxes due from your compensation as required by law, which, in the sole discretion of the Committee, may include withholding a number of MLP Common Units otherwise payable to you. PLAINS ALL AMERICAN, INC. By: /s/ Robert V. Sinnott -------------------------------------------- Robert V. Sinnott Chairman of the Compensation Committee of the Board of Directors
EXHIBIT 10.21 SECOND AMENDMENT TO CREDIT AGREEMENT THIS SECOND AMENDMENT TO CREDIT AGREEMENT (this "Amendment") dated as of the 19th day of August, 1999, by and among PLAINS SCURLOCK PERMIAN, L.P. ("Borrower") and BANKBOSTON, N.A., as Administrative Agent (in such capacity, "Administrative Agent"), and the Lenders party hereto. W I T N E S S E T H: WHEREAS, Borrower, Administrative Agent, and Lenders entered into that certain Credit Agreement dated as of May 12, 1999 (as amended, restated, or supplemented to the date hereof, the "Original Agreement") for the purposes and consideration therein expressed, pursuant to which Lenders became obligated to make and made loans to Borrower as therein provided; and WHEREAS, Borrower, Administrative Agent, and the Lenders party hereto desire to amend the Original Agreement for the purposes described herein. NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows: ARTICLE I. -- Definitions and References (S) 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment. (S) 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this (S) 1.2. "Amendment" means this Second Amendment to Credit Agreement. "Credit Agreement" means the Original Agreement as amended hereby. ARTICLE II. -- Amendment and Waiver (S) 2.1. Interest Rate Hedging Agreements. Section 6.18 of the Original Agreement is hereby amended to read in its entirety as follows: "Section 6.18. Interest Rate Hedging Agreements Borrower shall at all times maintain interest rate Hedging Contracts which are: (a) for combined durations as of any day of not less than 12 months following such time, (b) in combined notional amounts not less than seventy percent (70%) of the outstanding
principal balance of the Term Loans, (c) in compliance with Section 7.3, and (d) otherwise on terms acceptable to Administrative Agent in its sole discretion." (S) 2.2. Waiver. Administrative Agent and each other Lender Party hereby waives the (i) failure by Restricted Persons to comply with Section 6.18 of the Original Agreement prior to the date hereof and (ii) the related Defaults and Events of Default arising under Section 8.1(e) of the Original Agreement. ARTICLE III. -- Conditions of Effectiveness (S) 3.1. Effective Date. This Amendment shall become effective as of the date first above written when and only when Administrative Agent shall have received, at Administrative Agent's office (i) a counterpart of this Amendment executed and delivered by Restricted Persons and Majority Lenders and (ii) a certificate of a duly authorized officer of General Partner to the effect that all of the representations and warranties set forth in Article IV hereof are true and correct at and as of the time of such effectiveness. ARTICLE IV. -- Representations and Warranties (S) 4.1. Representations and Warranties. In order to induce Administrative Agent and Lenders to enter into this Amendment, Borrower and General Partner represent and warrant to Administrative Agent and each Lender that: (a) The representations and warranties contained in Article V of the Original Agreement, are true and correct at and as of the time of the effectiveness hereof except to the extent that such representation and warranty was made as of a specific date. (b) Each Restricted Person is duly authorized to execute and deliver this Amendment, and Borrower is and will continue to be duly authorized to borrow and perform its obligations under the Credit Agreement. Each Restricted Person has duly taken all action necessary to authorize the execution and delivery of this Amendment and to authorize the performance of its respective obligations hereunder. (c) The execution and delivery by each Restricted Person of this Amendment, the performance by each Restricted Person of its respective obligations hereunder, and the consummation of the transactions contemplated hereby, do not and will not conflict with any provision of law, statute, rule or regulation or of the constituent documents of any Restricted Person, or of any material agreement, judgment, license, order or permit applicable to or binding upon any Restricted Person, or result in the creation of any lien, charge or encumbrance upon any assets or properties of any Restricted Person, except in favor of Administrative Agent for the benefit of Lenders. Except for those which have been duly obtained, no consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by any Restricted Person of this Amendment, to the extent a party thereto, or to consummate the transactions contemplated hereby. 2
(d) When this Amendment has been duly executed and delivered, each of the Loan Documents, as amended by this Amendment, will be a legal and binding instrument and agreement of each Restricted Person, to the extent a party thereto, enforceable in accordance with its terms, (subject, as to enforcement of remedies, to applicable bankruptcy, insolvency and similar laws applicable to creditors' rights generally and to general principles of equity). (e) The Initial Financial Statements fairly present the Consolidated financial position at such date and the Consolidated statement of operations and the changes in financial position for the period ending on such date for Restricted Persons. Copies of such financial statements have heretofore been delivered to Lenders. Since July 15, 1999, no Material Adverse Change has occurred in the Consolidated financial condition or businesses of Restricted Persons. (f) No Default exists on the date hereof. (g) Each Restricted Person has performed and complied with all agreements and conditions required in the Loan Documents to be performed or complied with by it on or prior to the date hereof. ARTICLE V. -- Miscellaneous (S) 5.1. Ratification of Agreements. The Original Agreement, as hereby amended, is hereby ratified and confirmed in all respects. The Loan Documents, as they may be amended or affected by this Amendment, are hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Loan Document shall be deemed to refer to this Amendment also. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Administrative Agent or any Lender under the Credit Agreement or any other Loan Document nor constitute a waiver of any provision of the Credit Agreement or any other Loan Document. (S) 5.2. Survival of Agreements. All representations, warranties, covenants and agreements of the Restricted Persons herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of each Loan, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by any Restricted Person hereunder or under the Credit Agreement to Administrative Agent or any Lender shall be deemed to constitute representations and warranties by, or agreements and covenants of, such Restricted Person under this Amendment and under the Credit Agreement. (S) 5.3. Loan Documents. This Amendment is a Loan Document, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto and thereto. (S) 5.4. GOVERNING LAW. THIS AMENDMENT AND THE OTHER AMENDMENT DOCUMENTS SHALL BE GOVERNED BY AND CONSTRUED IN 3
ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY AND PERFORMANCE. (S) 5.5. Counterparts. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. 4
IN WITNESS WHEREOF, this Amendment is executed as of the date first above written. PLAINS SCURLOCK PERMIAN, L.P. By: PLAINS ALL AMERICAN INC., its general partner By: /s/ Michael R. Patterson -------------------------------- Name: Michael R. Patterson Title: Senior Vice President 5
BANKBOSTON, N.A., Administrative Agent, LC Issuer and Lender By: /s/ Terrence Ronan ----------------------------- Terrence Ronan Director 6
FIRST UNION NATIONAL BANK, as Syndication Agent and a Lender By: /s/ Robert R. Wetteroff ------------------------------------- Name: Robert R. Wetteroff Title: Senior Vice President 7
BANK ONE, TEXAS, N.A., as Documentation Agent and a Lender By: /s/ Jeanie C. Harman ----------------------- Name: Jeanie C. Harman Title: Vice President 8
PILGRIM PRIME RATE TRUST SEQUILS PILGRIM I LTD. ML CLO XX PILGRIM AMERICA (CAYMAN) LTD. By: PILGRIM INVESTMENTS, INC., as investment manager By: /s/ Robert L. Wilson ------------------------------- Name: Robert L. Wilson Title: Vice President 9
MORGAN STANLEY DEAN WITTER PRIME INCOME TRUST By: /s/ Sheila Finnerty ------------------------------------ Name: Sheila Finnerty Title: Vice President 10
MERRILL LYNCH SENIOR PRIME RATE PORTFOLIO, INC. By: MERRILL LYNCH ASSET MANAGEMENT, L.P., as Investment Advisor By: /s/ Andrew C. Liggio ------------------------------------ Name: Andrew C. Liggio Title: Assistant Vice President MERRILL LYNCH SENIOR FLOATING RATE FUND, INC. MERRILL LYNCH SENIOR FLOATING RATE FUND II, INC. DEBT STRATEGIES FUND II, INC. By: /s/ Andrew C. Liggio ---------------------------------------- Name: Andrew C. Liggio Title: Assistant Vice President 11
ELC (CAYMAN) LTD. CDO SERIES 1999-I By: /s/ Jeanette W. Bumgarner ---------------------------------------- Name: Jeanette E. Bumgarner Title: Vice President 12
FIRST UNION NATIONAL BANK By: /s/ Charles B. Edmondson ----------------------------------------- Name: Charles B. Edmondson Title: Assistant Vice President 13
CONSENT AND ACKNOWLEDGMENT Each of the undersigned hereby consents to the provisions of this Amendment and the transactions contemplated herein, and hereby ratifies and confirms its respective Guaranty dated as of May 12, 1999, made by it for the benefit of Administrative Agent, and agrees that its obligations and covenants thereunder are unimpaired hereby and shall remain in full force and effect. Date: August 19, 1999 SCURLOCK PERMIAN LLC By: /s/ Michael R. Patterson --------------------------------------- Name: Michael R. Patterson Title: Senior Vice President SCURLOCK PERMIAN PIPE LINE LLC By: /s/ Michael R. Patterson --------------------------------------- Name: Michael R. Patterson Title: Senior Vice President 14
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 10, 1999. Yours very truly, PricewaterhouseCoopers LLP San Francisco, California September 10, 1999
EXHIBIT 21.1 SUBSIDIARIES OF PLAINS ALL AMERICAN PIPELINE, L.P. ---------------------------------- Plains Marketing, L.P. All American Pipeline, L.P. Plains Scurlock Permian, L.P. Scurlock Permian LLC Scurlock Permian LLC
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 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. PricewaterhouseCoopers LLP Houston, Texas September 10, 1999
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. PricewaterhouseCoopers LLP San Francisco, California September 10, 1999
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. PricewaterhouseCoopers LLP Pittsburgh, Pennsylvania September 10, 1999