Use these links to rapidly review the document
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES TABLE OF CONTENTS



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-Q


ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended JuneSeptember 30, 2004

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-14569


PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
 76-0582150
(I.R.S. Employer
Identification No.)

333 Clay Street, Suite 1600
Houston, Texas 77002

(Address of principal executive offices)
(Zip Code)

(713) 646-4100 (Registrant's telephone number, including area code)

333 Clay Street, Suite 1600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)

(713) 646-4100
(Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý    No o

        At August 5,November 1, 2004, there were outstanding 62,628,72262,740,218 Common Units, 1,307,190 Class B Common Units and 3,245,700 Class C Common Units.





PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

 
Page
PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS:


Consolidated Balance Sheets:
 JuneSeptember 30, 2004 and December 31, 20033
Consolidated Statements of Operations:
 For the three months and sixnine months ended JuneSeptember 30, 2004 and 20034
Consolidated Statements of Cash Flows:
 For the sixnine months ended JuneSeptember 30, 2004 and 20035
Consolidated Statement of Partners' Capital:
 For the sixnine months ended JuneSeptember 30, 20046
Consolidated Statements of Comprehensive Income:
 For the three and sixnine months ended JuneSeptember 30, 2004 and 20037
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:
 For the sixnine months ended JuneSeptember 30, 20047
Notes to the Consolidated Financial Statements8
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS26
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS47
Item 4. CONTROLS AND PROCEDURES49

PART II. OTHER INFORMATION



Item 1. Legal Proceedings


50
Item 2. Changes in Securities and Use of Proceeds50
Item 3. Defaults Upon Senior Securities51
Item 4. Submission of Matters to a Vote of Security Holders51
Item 5. Other Information51
Item 6. Exhibits and Reports on Form 8-K51
Signatures52


PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS


PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)



 June 30,
2004

 December 31,
2003

 
 September 30,
2004

 December 31,
2003

 


 (unaudited)

 
 (unaudited)

 
ASSETSASSETS     ASSETS     

CURRENT ASSETS

CURRENT ASSETS

 

 

 

 

 
CURRENT ASSETS     
Cash and cash equivalentsCash and cash equivalents $12,056 $4,137 Cash and cash equivalents $4,547 $4,137 
Trade accounts receivable, netTrade accounts receivable, net 645,295 590,645 Trade accounts receivable, net 846,347 590,645 
InventoryInventory 128,534 105,967 Inventory 242,312 105,967 
Other current assetsOther current assets 43,564 32,225 Other current assets 55,501 32,225 
 
 
   
 
 
Total current assets 829,449 732,974 Total current assets 1,148,707 732,974 
 
 
   
 
 
PROPERTY AND EQUIPMENTPROPERTY AND EQUIPMENT 1,730,496 1,272,634 PROPERTY AND EQUIPMENT 1,824,314 1,272,634 
Accumulated depreciationAccumulated depreciation (147,949) (121,595)Accumulated depreciation (165,589) (121,595)
 
 
   
 
 
 1,582,547 1,151,039   1,658,725 1,151,039 
 
 
   
 
 
OTHER ASSETSOTHER ASSETS     OTHER ASSETS     
Pipeline linefill in owned assetsPipeline linefill in owned assets 148,680 95,928 Pipeline linefill in owned assets 159,985 95,928 
Inventory in third party assetsInventory in third party assets 38,745 26,725 Inventory in third party assets 46,359 26,725 
Other, netOther, net 82,483 88,965 Other, net 92,245 88,965 
 
 
   
 
 
Total assets $2,681,904 $2,095,631 Total assets $3,106,021 $2,095,631 
 
 
   
 
 
LIABILITIES AND PARTNERS' CAPITALLIABILITIES AND PARTNERS' CAPITAL     LIABILITIES AND PARTNERS' CAPITAL     

CURRENT LIABILITIES

CURRENT LIABILITIES

 

 

 

 

 
CURRENT LIABILITIES     
Accounts payableAccounts payable $763,659 $603,460 Accounts payable $965,265 $603,460 
Due to related partiesDue to related parties 27,195 26,981 Due to related parties 33,447 26,981 
Short-term debtShort-term debt 21,989 127,259 Short-term debt 122,882 127,259 
Other current liabilitiesOther current liabilities 42,803 44,219 Other current liabilities 77,641 44,219 
 
 
   
 
 
Total current liabilities 855,646 801,919 Total current liabilities 1,199,235 801,919 
 
 
   
 
 
LONG-TERM LIABILITIESLONG-TERM LIABILITIES     LONG-TERM LIABILITIES     
Long-term debt under credit facilitiesLong-term debt under credit facilities 485,774 70,000 Long-term debt under credit facilities 40,408 70,000 
Senior notes, net of unamortized discount of $957 and $1,009, respectively 449,043 448,991 
Senior notes, net of unamortized discount of $2,820 and $1,009, respectivelySenior notes, net of unamortized discount of $2,820 and $1,009, respectively 797,180 448,991 
Other long-term liabilities and deferred creditsOther long-term liabilities and deferred credits 25,922 27,994 Other long-term liabilities and deferred credits 24,780 27,994 
 
 
   
 
 
Total liabilities 1,816,385 1,348,904 Total liabilities 2,061,603 1,348,904 
 
 
   
 
 
COMMITMENTS AND CONTINGENCIES (NOTE 9)     
COMMITMENTS AND CONTINGENCIES (NOTE 10)COMMITMENTS AND CONTINGENCIES (NOTE 10)     

PARTNERS' CAPITAL

PARTNERS' CAPITAL

 

 

 

 

 

PARTNERS' CAPITAL

 

 

 

 

 
Common unitholders (57,724,722 and 49,502,556 units outstanding at June 30, 2004, and December 31, 2003, respectively) 722,110 744,073 
Common unitholders (62,740,218 and 49,502,556 units outstanding at September 30, 2004, and December 31, 2003, respectively)Common unitholders (62,740,218 and 49,502,556 units outstanding at September 30, 2004, and December 31, 2003, respectively) 895,479 744,073 
Class B common unitholder (1,307,190 units outstanding at each date)Class B common unitholder (1,307,190 units outstanding at each date) 17,951 18,046 Class B common unitholder (1,307,190 units outstanding at each date) 18,302 18,046 
Class C common unitholders (3,245,700 units and no units outstanding at June 30, 2004, and December 31, 2003, respectively) 98,297  
Subordinated unitholders (no units and 7,522,214 units outstanding at June 30, 2004, and December 31, 2003, respectively)  (39,913)
Class C common unitholders (3,245,700 units and no units outstanding at September 30, 2004, and December 31, 2003, respectively)Class C common unitholders (3,245,700 units and no units outstanding at September 30, 2004, and December 31, 2003, respectively) 98,856  
Subordinated unitholders (no units and 7,522,214 units outstanding at September 30, 2004, and December 31, 2003, respectively)Subordinated unitholders (no units and 7,522,214 units outstanding at September 30, 2004, and December 31, 2003, respectively)  (39,913)
General partnerGeneral partner 27,161 24,521 General partner 31,781 24,521 
 
 
   
 
 
Total partners' capital 865,519 746,727 Total partners' capital 1,044,418 746,727 
 
 
   
 
 
Total liabilities and partners' capital $2,681,904 $2,095,631   $3,106,021 $2,095,631 
 
 
   
 
 

The accompanying notes are an integral part of these consolidated financial statements.



PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)



 Three Months Ended
June 30,

 Six Months Ended
June 30,

 
 Three Months Ended
September 30,

 Nine Months Ended
September 30,

 


 2004
 2003
 2004
 2003
 
 2004
 2003
 2004
 2003
 


 (unaudited)

 (unaudited)

 
 (unaudited)

 (unaudited)

 
REVENUESREVENUES         REVENUES         
Crude oil and LPG salesCrude oil and LPG sales $4,939,467 $2,557,284 $8,555,451 $5,672,571 Crude oil and LPG sales $5,663,504 $2,897,112 $14,218,956 $8,572,569 
Other gathering, marketing, terminalling and storage revenuesOther gathering, marketing, terminalling and storage revenues 1,608 8,608 16,727 15,957 Other gathering, marketing, terminalling and storage revenues 11,193 8,221 27,920 22,777 
Pipeline margin activities revenuesPipeline margin activities revenues 138,831 117,515 281,166 252,686 Pipeline margin activities revenues 142,999 123,974 424,165 376,660 
Pipeline tariff activities revenuesPipeline tariff activities revenues 51,829 25,782 83,035 49,883 Pipeline tariff activities revenues 49,309 24,370 132,343 72,768 
 
 
 
 
   
 
 
 
 
Total revenues 5,131,735 2,709,189 8,936,379 5,991,097 Total revenues 5,867,005 3,053,677 14,803,384 9,044,774 

COSTS AND EXPENSES

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 
COSTS AND EXPENSES         
Crude oil and LPG purchases and related costsCrude oil and LPG purchases and related costs 4,859,173 2,508,709 8,416,244 5,569,420 Crude oil and LPG purchases and related costs 5,576,523 2,849,286 13,992,768 8,417,316 
Pipeline margin activities purchasesPipeline margin activities purchases 132,694 112,601 269,128 243,131 Pipeline margin activities purchases 138,530 119,119 407,658 362,250 
Field operating costs (excluding LTIP charge)Field operating costs (excluding LTIP charge) 59,035 32,574 96,851 65,689 Field operating costs (excluding LTIP charge) 61,203 33,222 158,053 100,301 
LTIP charge—operationsLTIP charge—operations   567  LTIP charge—operations  1,390 567 1,390 
General and administrative expenses (excluding LTIP charge)General and administrative expenses (excluding LTIP charge) 19,603 12,161 35,081 25,233 General and administrative expenses (excluding LTIP charge) 19,484 12,198 54,565 37,431 
LTIP charge—general and administrativeLTIP charge—general and administrative   3,661  LTIP charge—general and administrative  6,006 3,661 6,006 
Depreciation and amortizationDepreciation and amortization 15,998 11,305 29,118 22,176 Depreciation and amortization 16,768 11,988 45,887 34,164 
 
 
 
 
   
 
 
 
 
Total costs and expenses 5,086,503 2,677,350 8,850,650 5,925,649 Total costs and expenses 5,812,508 3,033,209 14,663,159 8,958,858 
 
 
 
 
   
 
 
 
 
Gains on sales of assetsGains on sales of assets 559 474 643 608 
 
 
 
 
 
OPERATING INCOMEOPERATING INCOME 45,232 31,839 85,729 65,448 OPERATING INCOME 55,056 20,942 140,868 86,524 
 
 
 
 
   
 
 
 
 
OTHER INCOME/(EXPENSE)OTHER INCOME/(EXPENSE)         OTHER INCOME/(EXPENSE)         
Interest expense (net of $219 and $244 capitalized for the three month periods, respectively, and $397 and $296 capitalized for the six month periods, respectively) (9,967) (8,532) (19,499) (17,686)
Interest and other income (expense), net 412 91 453 (13)
Interest expense (net of $32 and $165 capitalized for the three month periods, respectively, and $207 and $461 capitalized for the nine month periods, respectively)Interest expense (net of $32 and $165 capitalized for the three month periods, respectively, and $207 and $461 capitalized for the nine month periods, respectively) (12,702) (8,794) (32,201) (26,480)
Interest income and other, netInterest income and other, net (620) (277) (250) (424)
 
 
 
 
   
 
 
 
 
Income before cumulative effect of change in accounting principleIncome before cumulative effect of change in accounting principle 35,677 23,398 66,683 47,749 Income before cumulative effect of change in accounting principle 41,734 11,871 108,417 59,620 
Cumulative effect of change in accounting principleCumulative effect of change in accounting principle   (3,130)  Cumulative effect of change in accounting principle   (3,130)  
 
 
 
 
   
 
 
 
 
NET INCOMENET INCOME $35,677 $23,398 $63,553 $47,749 NET INCOME $41,734 $11,871 $105,287 $59,620 
 
 
 
 
   
 
 
 
 
NET INCOME-LIMITED PARTNERSNET INCOME-LIMITED PARTNERS $33,247 $21,690 $58,954 $44,566 NET INCOME-LIMITED PARTNERS $38,738 $10,392 $97,692 $54,958 
 
 
 
 
   
 
 
 
 
NET INCOME-GENERAL PARTNERNET INCOME-GENERAL PARTNER $2,430 $1,708 $4,599 $3,183 NET INCOME-GENERAL PARTNER $2,996 $1,479 $7,595 $4,662 
 
 
 
 
   
 
 
 
 
BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT         
BASIC NET INCOME PER LIMITED PARTNER UNITBASIC NET INCOME PER LIMITED PARTNER UNIT         
Income before cumulative effect of change in accounting principleIncome before cumulative effect of change in accounting principle $0.54 $0.42 $1.03 $0.87 Income before cumulative effect of change in accounting principle $0.59 $0.20 $1.63 $1.06 
Cumulative effect of change in accounting principleCumulative effect of change in accounting principle   (0.05)  Cumulative effect of change in accounting principle   (0.05)  
 
 
 
 
   
 
 
 
 
Net income $0.54 $0.42 $0.98 $0.87 
Basic net income per limited partner unitBasic net income per limited partner unit $0.59 $0.20 $1.58 $1.06 
 
 
 
 
   
 
 
 
 
WEIGHTED AVERAGE UNITS OUTSTANDING 61,556 52,223 59,985 51,200 
DILUTED NET INCOME PER LIMITED PARTNER UNITDILUTED NET INCOME PER LIMITED PARTNER UNIT         
Income before cumulative effect of change in accounting principleIncome before cumulative effect of change in accounting principle $0.59 $0.19 $1.63 $1.05 
Cumulative effect of change in accounting principleCumulative effect of change in accounting principle   (0.05)  
 
 
 
 
   
 
 
 
 
Diluted net income per limited partner unitDiluted net income per limited partner unit $0.59 $0.19 $1.58 $1.05 
 
 
 
 
 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

65,776

 

52,788

 

61,929

 

51,735

 
 
 
 
 
 
DILUTED WEIGHTED AVERAGE UNITS
OUTSTANDING
DILUTED WEIGHTED AVERAGE UNITS
OUTSTANDING
 65,776 53,435 61,929 52,407 
 
 
 
 
 

The accompanying notes are an integral part of these consolidated financial statements.



PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



 Six Months Ended
June 30,

 
 Nine Months Ended
September 30,

 


 2004
 2003
 
 2004
 2003
 


 (unaudited)

 
 (unaudited)

 
CASH FLOWS FROM OPERATING ACTIVITIESCASH FLOWS FROM OPERATING ACTIVITIES     CASH FLOWS FROM OPERATING ACTIVITIES     
Net incomeNet income $63,553 $47,749 Net income $105,287 $59,620 
Adjustments to reconcile to cash flows from operating activities:Adjustments to reconcile to cash flows from operating activities:     Adjustments to reconcile to cash flows from operating activities:     
Depreciation and amortization 45,887 34,164 
Cumulative effect of accounting change 3,130  
Change in derivative fair value (1,431) 1,731 
Noncash portion of LTIP charge 4,228 3,700 
Depreciation and amortization 29,118 22,176 Gain on foreign currency revaluation (3,423)  
Cumulative effect of change in accounting principle 3,130   Noncash amortization of terminated interest rate swap 1,092  
Change in derivative fair value (556) (1,155)Loss on refinancing of debt 658  
Noncash portion of LTIP charge 4,228  Gain on sale of assets (643) (608)
Noncash amortization of terminated interest rate swap 714  Net cash paid for terminated swaps (1,465)  
Changes in assets and liabilities, net of acquisitions:Changes in assets and liabilities, net of acquisitions:     Changes in assets and liabilities, net of acquisitions:     
Accounts receivable and other (28,575) 52,402 Trade accounts receivable and other (285,123) 132,366 
Inventory (24,135) 41,015 Inventory (127,391) (84,690)
Accounts payable and other current liabilities 99,423 35,718 Accounts payable and other current liabilities 365,784 84,717 
Settlement of environmental indemnities  4,600 Settlement of environmental indemnities  4,600 
Due to related parties 210 2,292 Due to related parties 6,461 500 
 
 
   
 
 
 Net cash provided by operating activities 147,110 204,797  Net cash provided by operating activities 113,051 236,100 
 
 
   
 
 
CASH FLOWS FROM INVESTING ACTIVITIESCASH FLOWS FROM INVESTING ACTIVITIES     CASH FLOWS FROM INVESTING ACTIVITIES     
Cash paid in connection with acquisitions (Note 2) (443,210) (79,616)
Cash paid in connection with acquisitionsCash paid in connection with acquisitions (495,715) (99,897)
Additions to property and equipmentAdditions to property and equipment (32,170) (37,492)Additions to property and equipment (63,596) (52,180)
Cash paid for linefill on assets owned  (28,478)
Cash paid for linefill in assets ownedCash paid for linefill in assets owned (10,242) (40,449)
Proceeds from sales of assetsProceeds from sales of assets 737 5,790 Proceeds from sales of assets 2,234 7,076 
Other investing activitiesOther investing activities  232 
 
 
   
 
 
 Net cash used in investing activities (474,643) (139,796) Net cash used in investing activities (567,319) (185,218)
 
 
   
 
 
CASH FLOWS FROM FINANCING ACTIVITIESCASH FLOWS FROM FINANCING ACTIVITIES     CASH FLOWS FROM FINANCING ACTIVITIES     
Net borrowings on long-term revolving credit facility 415,827 29,089 
Net repayments on working capital revolving credit facility (12,100)  
Net repayments on long-term revolving credit facilityNet repayments on long-term revolving credit facility (29,977) (13,122)
Net borrowings on working capital revolving credit facilityNet borrowings on working capital revolving credit facility 34,700  
Net repayments on short-term letter of credit and hedged inventory facilityNet repayments on short-term letter of credit and hedged inventory facility (96,091) (90,178)Net repayments on short-term letter of credit and hedged inventory facility (42,234) (67,315)
Net borrowings on other short-term debt (1,641)  
Principal payments on senior secured term loanPrincipal payments on senior secured term loan  (7,000)Principal payments on senior secured term loan  (43,000)
Cash paid in connection with financing arrangementsCash paid in connection with financing arrangements (500) (60)Cash paid in connection with financing arrangements (3,172) (87)
Proceeds from the issuance of senior notesProceeds from the issuance of senior notes 346,427  
Net proceeds from the issuance of common unitsNet proceeds from the issuance of common units 101,213 63,895 Net proceeds from the issuance of common units 262,132 161,905 
Distributions paid to unitholders and general partnerDistributions paid to unitholders and general partner (72,673) (58,772)Distributions paid to unitholders and general partner (114,468) (89,346)
 
 
   
 
 
 Net cash provided by (used in) financing activities 334,035 (63,026) Net cash provided by (used in) financing activities 453,408 (50,965)
 
 
   
 
 

Effect of translation adjustment on cash

Effect of translation adjustment on cash

 

1,417

 

94

 

Effect of translation adjustment on cash

 

1,270

 


 

Net increase in cash and cash equivalents

 

7,919

 

2,069

 

Net increase (decrease) in cash and cash equivalents

Net increase (decrease) in cash and cash equivalents

 

410

 

(83

)
Cash and cash equivalents, beginning of periodCash and cash equivalents, beginning of period 4,137 3,501 
Cash and cash equivalents, beginning of period

 

4,137

 

3,501

 
 
 
   
 
 
Cash and cash equivalents, end of periodCash and cash equivalents, end of period $12,056 $5,570 
Cash and cash equivalents, end of period

 

$

4,547

 

$

3,418

 
 
 
   
 
 

Cash paid for interest, net of amounts capitalized

Cash paid for interest, net of amounts capitalized

 

$

20,547

 

$

19,092

 

Cash paid for interest, net of amounts capitalized

 

$

23,366

 

$

24,286

 
 
 
   
 
 

The accompanying notes are an integral part of these consolidated financial statements.



PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

(in thousands)


  
  
 Class B
Common Units

 Class C
Common Units

  
  
  
  
  
 

 Common Units
 Subordinated Units
  
  
 Total
Partners'
Capital
Amount

 

 Common Units
 Class B
Common Units

 Class C
Common Units

 Subordinated Units
 General
Partner

 Total
Partners'
Capital

  Class C
Common Units

 

 Units
 Amount
 Units
 Amount
 Units
 Amount
 Units
 Amount
 Amount
 Amount
  Units
 Amount
 General
Partners'
Amount

 Total
Units

 Units
 Amount
 Units
 Amount
Total
Partners'
Capital
Amount


 (unaudited)

  (unaudited)

  
Balance at December 31, 2003 49,502 $744,073 1,307 $18,046  $ 7,523 $(39,913)$24,521 $746,727  49,502 $744,073 1,307 $18,046  $ 7,523 $(39,913)$24,521 58,332 $746,727
Issuance of common units 4,968  157,568           3,371 4,968  160,939 
Issuance of common
units under LTIP
 315  10,250           208  10,458  362  11,772           238 362  12,010 
Private placement of Class C common units       3,246  98,831     2,041  100,872        3,246  98,782     2,041 3,246  100,823 
Payment of deferred acquisition price 385  13,082           267  13,349 
Issuance of units for acquisition contingent consideration 385  13,082           267 385  13,349 
Distributions   (60,363)  (1,470)  (1,826)  (4,231) (4,783) (72,673)   (96,531)  (2,225)  (3,700)  (4,231) (7,781)  (114,468)
Other comprehensive income   3,604   84   78   (841) 308  3,233    18,029   410   624   (841) 1,529   19,751 
Net income   55,005   1,291   1,214   1,444  4,599  63,553    91,027   2,071   3,150   1,444  7,595   105,287 
Conversion of subordinated units 7,523  (43,541)      (7,523) 43,541      7,523  (43,541)      (7,523) 43,541      
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
Balance at June 30,
2004
 57,725 $722,110 1,307 $17,951 3,246 $98,297  $ $27,161 $865,519 
Balance at September 30, 2004 62,740 $895,479 1,307 $18,302 3,246 $98,856  $ $31,781 67,293 $1,044,418 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 

The accompanying notes are an integral part of these consolidated financial statements.



PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in thousands)

Statements of Comprehensive Income

 
 Three Months Ended
June 30,

 Six Months Ended
June 30,

 
 2004
 2003
 2004
 2003
 
 (unaudited)

 (unaudited)

Net income $35,677 $23,398 $63,553 $47,749
Other comprehensive income  14,047  16,390  3,233  36,313
  
 
 
 
Comprehensive income $49,724 $39,788 $66,786 $84,062
  
 
 
 
 
 Three Months Ended
September 30,

 Nine Months Ended
September 30,

 
 2004
 2003
 2004
 2003
 
 (unaudited)

 (unaudited)

Net income $41,734 $11,871 $105,287 $59,620
Other comprehensive income  16,518  25,286  19,751  61,599
  
 
 
 
Comprehensive income $58,252 $37,157 $125,038 $121,219
  
 
 
 


Statement of Changes in Accumulated Other Comprehensive Income



 Net Deferred
Gain (Loss) on
Derivative
Instruments

 Currency
Translation
Adjustments

 Total
 
 Net Deferred
Gain (Loss) on
Derivative
Instruments

 Currency
Translation
Adjustments

 Total
 


 (unaudited)

 
 (unaudited)

 
Balance at December 31, 2003Balance at December 31, 2003 $(7,692)$39,861 $32,169 Balance at December 31, 2003 $(7,692)$39,861 $32,169 
Current period activity:       Current period activity:       
Reclassification adjustments for settled contracts 7,832  7,832  Reclassification adjustments for settled contracts 20,265  20,265 
Changes in fair value of outstanding hedge positions 4,418  4,418  Changes in fair value of outstanding hedge positions (12,160)  (12,160)
Currency translation adjustment  (9,017) (9,017) Currency translation adjustment  11,646 11,646 
 
 
 
   
 
 
 
Total period activity 12,250 (9,017) 3,233 Total period activity 8,105 11,646 19,751 
 
 
 
   
 
 
 
Balance at June 30, 2004 $4,558 $30,844 $35,402 
Balance at September 30, 2004Balance at September 30, 2004 $413 $51,507 $51,920 
 
 
 
   
 
 
 

The accompanying notes are an integral part of these consolidated financial statements.



PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

        Plains All American Pipeline, L.P. is a publicly traded Delaware limited partnership (the "Partnership") engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." Our operations are conducted in the United States and Canada, directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. (formerly known as All American Pipeline, L.P.) and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana, Kansas and the Canadian provinces of Alberta and Saskatchewan.

        The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of JuneSeptember 30, 2004, and December 31, 2003, (ii) the results of our consolidated operations for the three months and sixnine months ended JuneSeptember 30, 2004 and 2003, (iii) our consolidated cash flows for the sixnine months ended JuneSeptember 30, 2004 and 2003, (iv) our consolidated changes in partners' capital for the sixnine months ended JuneSeptember 30, 2004, (v) our consolidated comprehensive income for the three months and sixnine months ended JuneSeptember 30, 2004 and 2003, and (vi) our changes in consolidated accumulated other comprehensive income for the sixnine months ended JuneSeptember 30, 2004. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the three months and sixnine months ended JuneSeptember 30, 2004 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2003 Annual Report on Form 10-K/A Amendment No. 1.

Foreign Currency Transactions

        For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at period end rates of exchange and revenues and expenses are translated at average exchange rates prevailing for each month. Translation adjustments for the asset and liability accounts are included as a separate component of other comprehensive income in partners' capital. Currency transaction gains and losses are recorded in income.

Change in Accounting Principle

        During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we have not included linefill barrels in the same average costing calculation as our operating inventory, but instead have carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, will beis included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify the linefill in third party assets not expected to be



liquidated within the succeeding twelve months out of "Inventory" (a current asset), at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is now reflected as a separate line item within other assets on the consolidated balance sheet.

        This change in accounting principle is effective January 1, 2004 and is reflected in the consolidated statement of operations for the sixnine months ended JuneSeptember 30, 2004 and the consolidated balance sheet as of JuneSeptember 30, 2004, included herein. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an



increase in Inventory in Third Party Assets of $28.9 million. The pro forma impact for the secondthird quarter of 2003 was not material to net income or net income per basic and diluted limited partner unit. The pro forma impact for the first halfnine months of 2003 would have been an increase to net income of approximately $1.8$2.2 million ($0.04 per basic and diluted limited partner unit) resulting in pro forma net income of $49.6$61.8 million and pro forma basic net income per limited partner unit (basicof $1.10 and diluted)pro forma diluted net income per limited partner unit of $0.91.$1.09.

        In conjunction with this change in accounting principle, we will classifyhave classified cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification asof cash flows from operating activities. Accordingly, the accompanying statement of cash flows for the sixnine months ended JuneSeptember 30, 2003 has been revised to reclassify the cash paid for linefill in assets owned from operating activities to investing activities. The effect of the reclassification was an increase to net cash provided by operating activities and net cash used in investing activities of $28.5$40.4 million for the sixnine months ended JuneSeptember 30, 2003. As a result of this change in classification, net cash provided by operating activities for the years ended December 31, 2003 and 2002 would increase to $115.3 million from $68.5 million and to $185.0 million from $173.9 million, respectively. Net cash used in investing activities for the years ended December 31, 2003 and 2002 would increase to $272.1 million from $225.3 million and $374.8 million from $363.8 million, respectively. In addition, net cash used in operating activities for the year ended December 31, 2001 would decrease from $30 million to $16.2 million and net cash used in investing activities would increase to $263.2 million from $249.5 million.

Note 2—Acquisitions and Dispositions

        The following acquisitions were made in 2004 and were accounted for under Statement of Financial Accounting Standards ("SFAS") No. 141 "Business Combinations."

        On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $326$332 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $58$64 million of net liabilities assumed and acquisition relatedacquisition-related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and gathering, marketing, terminalling and storage operations segments since April 1, 2004.


        The purchase price was allocated as follows and includes goodwill primarily related to Link's gathering and marketing business (in millions):

Fair value of assets acquired:Fair value of assets acquired:   Fair value of assets acquired:   
Property and equipmentProperty and equipment $256.3 Property and equipment $262.3 
InventoryInventory 1.1 Inventory 1.1 
LinefillLinefill 48.4 Linefill 48.4 
Inventory in third party assetsInventory in third party assets 15.1 Inventory in third party assets 15.1 
GoodwillGoodwill 5.0 Goodwill 5.0 
Other long term assetsOther long term assets 0.2 Other long term assets 0.2 
 
   
 
Subtotal 326.1 Subtotal 332.1 

Accounts receivable(1)

Accounts receivable(1)

 

405.4

 

Accounts receivable(1)

 

405.4

 
Other current assetsOther current assets 1.8 Other current assets 1.8 
 
   
 
Subtotal 407.2 Subtotal 407.2 

Total assets acquired

 

733.3

 

Total assets acquired

Total assets acquired

 

739.3

 

Fair value of liabilities assumed:

Fair value of liabilities assumed:

 

 

 

Fair value of liabilities assumed:

 

 

 
Accounts payable and accrued liabilities(1)Accounts payable and accrued liabilities(1) (448.9)Accounts payable and accrued liabilities(1) (455.4)
Other current liabilitiesOther current liabilities (8.5)Other current liabilities (8.5)
Other long-term liabilitiesOther long-term liabilities (7.4)Other long-term liabilities (7.4)
 
   
 
Total liabilities assumed (464.8)Total liabilities assumed (471.3)

Cash paid for acquisition(2)

Cash paid for acquisition(2)

 

$

268.5

(1)

Cash paid for acquisition(2)

 

$

268.0

 
 
   
 

(1)
Accounts receivable and accounts payable are gross and do not reflect the adjustment of approximately $250 million to net settle, based on contractual agreements with our counterparties.

(2)
Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs.

        We are in the process of evaluating certain estimates made in the purchase price and related allocation; thus, the purchase price and allocation are both subject to refinement. In addition, we anticipate making capital expenditures of approximately $19.1$20.0 million ($9.0 million in 2004) to upgrade certain of the assets and comply with certain regulatory requirements.

        The acquisition was initially funded with cash on hand, borrowings under our revolving credit facilities and under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities (see Note 4)5). In connection with the acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit, generating aggregate net proceeds of approximately $101 million, including the general partner's proportionate contribution.investors. During the third quarter of 2004, we completed a public offering of common units raising approximately $159and the sale of an aggregate of $350 million net of expenses and inclusivesenior notes. A portion of the underwriters' exercise of the overallotment option and the general partner's proportionate contribution. Proceedsproceeds from the public offering werethese transactions was used to retire a portion of the $200 million, 364-day credit facility. Seefacility (see Note 6.7).

        On April 2, 2004, the Office of the Attorney General of Texas (the "Texas AG") delivered written notice to us that it was investigating the possibility that the acquisition of Link's assets might reduce competition in one or more markets within the petroleum products industry in the State of Texas. In



connection with the Link purchase, both PAA and Link completed all necessary filings required under the Hart-Scott-Rodino Act, and the required 30-day waiting period expired on March 24, 2004 without any inquiry or request for additional information from the U.S. Department of Justice or the Federal Trade Commission. Representatives from the Antitrust and Civil Medicaid Fraud Division of the Office of the Attorney General of Texas (the "Texas AG Antitrust Division") indicated their investigation was prompted by complaints received from allegedly interested industry parties regarding the potential impact on competition in the Permian Basin area of West Texas. We understand that similar complaints have been received by the Federal Trade Commission (the "FTC"), and that, consistent with federal-state protocols for conducting joint merger investigations, appropriate federal and state antitrust authorities are coordinating their activities. We have cooperated fully with the antitrust enforcement authorities, including the provision of information at the request of the Texas AG Antitrust Division. We have been informed by the Texas AG Antitrust Division that it is closing its investigation and does not intend to pursue any additional course of action with respect to these assets at this time. We have not yet received an indication from the FTC as to whether it intends to close its investigation.

        In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's interests in two entities for approximately $158.0 million in cash (including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million, after paying approximately $4.1 million of transaction costs. The proceeds from this issuance were used to pay down


our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility.

        The principal assets of these entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 667-mile,633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets from this acquisition (the "Capline acquisition") have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S., and delivered to several refineries and other pipelines.

        The purchase price was allocated as follows (in millions):

Crude oil pipelines and facilities $151.4
Crude oil storage and terminal facilities  5.7
Land  1.3
Office equipment and other  0.1
  
Total $158.5
  

        The following unaudited pro forma data is presented to show pro forma revenues, income before cumulative effect of change in accounting principle, net income, basic and diluted income before cumulative effect of accounting change per limited partner unit and basic and diluted net income per limited partner unit for the Partnership as if the Capline and Link acquisitions had occurred as of the beginning of the periods reported (in millions, except per unit amounts):reported:


 Three Months Ended
September 30,

 Nine Months Ended
September 30,


 Six Months Ended
June 30,

 2004
 2003
 2004
 2003

 2004
 2003
 (in millions, except per unit amounts)

Revenues $8,984.3 $6,106.8 $5,867.0 $3,104.9 $14,851.3 $9,211.7
 
 
 
 
 
 
Income before cumulative effect of change in accounting principle(1) $49.5 $108.9 $41.7 $(3.6)$91.2 $105.3
 
 
 
 
 
 
Net income(2) $46.4 $104.9 $41.7 $(3.6)$88.1 $101.3
 
 
 
 
 
 
Basic and diluted income before cumulative effect of change in accounting principle per limited partner unit(1) $0.76 $2.04
Basic income before cumulative effect of change in accounting principle per limited partner unit(1) $0.59 $(0.09)$1.35 $1.95
 
 
 
 
 
 
Basic and diluted net income per limited partner unit(2) $0.70 $1.97
Diluted income before cumulative effect of change in accounting principle per limited partner unit(1) $0.59 $(0.09)$1.35 $1.93
 
 
 
 
 
 
Basic net income per limited partner unit(2) $0.59 $(0.09)$1.30 $1.87
 
 
 
 
Diluted net income per limited partner unit(2) $0.59 $(0.09)$1.30 $1.86
 
 
 
 

(1)
Includes a net gain in the 2003 period of approximately $67.5 million related to Link's predecessor company's reorganization, discharge of debt and fresh start adjustments.

(2)
The 2003 period includes the amounts described in note (1) above for Link's predecessor company's reorganization, discharge of debt and fresh start adjustments along withas well as a loss of approximately $4.0 million related to Link's predecessor company's cumulative effect of change in accounting principle.

        The following acquisitions, both individually and in the aggregate, are not material, and thus, no supplemental pro forma information is included herein.

        In August 2004, we completed the acquisition of the Schaefferstown Propane Storage Facility from Koch Hydrocarbon, L.P. The total purchase price was approximately $32 million, including transaction costs. In connection with the transaction, the Partnership also acquired an additional $14.2 million of inventory. The transaction was funded through a combination of cash on hand and borrowings under the Partnership's revolving credit facilities. The facility is located approximately 65 miles northwest of Philadelphia near Schaefferstown, Pennsylvania, and has the capacity to store approximately 20.0 million gallons of refrigerated propane. In addition, the facility has 19 bullet storage tanks with an aggregate capacity of 570,000 gallons. Propane is delivered to the facility via truck or pipeline and is transported out of the facility by truck. In addition, the transaction also included approximately 61 acres of land and a truck rack. The results of operations and assets from this acquisition have been



included in our consolidated financial statements and our gathering, marketing, terminalling and storage operations segment since August 25, 2004. The preliminary purchase price was primarily allocated to property and equipment.

        On May 7, 2004, we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately


$19 $19 million, including transaction costs. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The Cal Ven Pipeline System includes approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is located in northern Alberta and delivers crude oil into the Rainbow Pipeline System. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004.

        We acquired an interest in the Rancho Pipeline System from Shell in August 2002. The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, would terminate in March 2003. Upon termination, the agreement required the owners to take the pipeline system, in which we owned an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. This shutdown was contemplated at the time of the acquisition and was accounted for under purchase accounting in accordance with SFAS No. 141 "Business Combinations." The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. In June 2003, we completed transactions whereby we transferred our ownership interest in approximately 241 miles of the total 458 miles of the pipeline in exchange for $4.0 million and approximately 500,000 barrels of crude oil tankage in West Texas. In August 2004, we sold our interest in the remaining portion of the system to Kinder Morgan Texas Pipeline, L.P. for approximately $0.9 million, including the assumption of all liabilities typically associated with pipelines of this type. We recognized a gain of approximately $0.6 million on this transaction.

Note 3—Trade Accounts Receivable

        The majority of our trade accounts receivable relate to our gathering and marketing activities and can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At JuneSeptember 30, 2004, approximately 99% of our net trade accounts receivable were less than 60 days past the scheduled invoice date. Our allowance for doubtful



trade accounts receivable totaled $0.4$0.5 million. We consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 4—Inventory and Linefill

        Inventory primarily consists of crude oil and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. Linefill and minimum working inventory requirements are recorded at historical cost and consist of crude oil and LPG used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location, as well as the minimum amount of crude oil necessary to operate our storage and terminalling facilities.

        Linefill in third party assets is included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory," at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.

At September 30, 2004 and December 31, 2003, inventory and linefill consisted of:

 
 September 30, 2004
 December 31, 2003
 
 Barrels
 Dollars
 $/
barrel

 Barrels
 Dollars
 $/
barrel

 
 (Barrels in thousands and dollars in millions)

Inventory(1)                
Crude oil 2,802 $110.1 $39.29 1,676 $50.6 $30.19
LPG 3,874  130.3  33.63 2,243  53.8  23.99
Other   1.9  N/A   1.6  N/A
  
 
    
 
   
 Inventory subtotal 6,676  242.3    3,919  106.0   

Inventory in third-party assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Crude oil 1,137  40.6  35.71 853  22.6  26.49
LPG 183  5.7  31.15 183  4.1  22.40
  
 
    
 
   
 Inventory in third-party assets subtotal 1,320  46.3    1,036  26.7   

Linefill

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Crude oil linefill 5,804  160.0  27.57 3,767  95.9  25.46
  
 
    
 
   
Total 13,800 $448.6    8,722 $228.6   
  
 
    
 
   

(1)
Value per barrel reflects the impact of inventory hedges on a portion of our volumes.


Note 4—5—Debt

      Debt consists of the following (in millions):following:

 
 June 30,
2004

 December 31,
2003

Short-term debt:      

Senior secured hedged inventory borrowing facility bearing interest at a rate of 2.0% and 1.9% at June 30, 2004 and December 31, 2003, respectively

 

$

4.4

 

$

100.5
Working capital borrowings on senior unsecured $425 million domestic revolving credit facility, bearing interest at a rate of 4.0% at both June 30, 2004 and December 31, 2003, respectively(1)  13.2  25.3
Other  4.4  1.5
  
 
 Total short-term debt  22.0  127.3

Long-term debt:

 

 

 

 

 

 

$200 million revolving credit facility, bearing interest at a rate of 2.3% at June 30, 2004

 

$

200.0

 

$

Senior unsecured $425 million domestic revolving credit facility, bearing interest at 2.3% at June 30, 2004(1)  90.0  
Senior unsecured $30 million Canadian working capital revolving credit facilty, bearing interest at a rate of 4.4% at June 30, 2004  25.7  
Senior unsecured $170 million Canadian revolving credit facility, bearing interest at a rate of 2.3% and 2.2% at June 30, 2004 and December 31, 2003, respectively  170.0  70.0
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.3 million at June 30, 2004 and December 31, 2003, respectively  199.7  199.7
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million and $0.7 million at June 30, 2004 and December 31, 2003, respectively  249.4  249.3
  
 
 Total long-term debt(1)  934.8  519.0
  
 
Total debt $956.8 $646.3
  
 
 
 September 30,
2004

 December 31,
2003

 
 (in millions)

Short-term debt:      
Senior secured hedged inventory borrowing facility bearing interest at a rate of 2.6% and 1.9% at September 30, 2004 and December 31, 2003, respectively $59.5 $100.5
Working capital borrowings, bearing interest at a rate of 2.8% and 4.0% at September 30, 2004 and December 31, 2003, respectively(1)  60.0  25.3
Other  3.4  1.5
  
 
 Total short-term debt  122.9  127.3

Long-term debt:

 

 

 

 

 

 
Senior unsecured $425 million domestic revolving credit facility, bearing interest at 4.8% at September 30, 2004(1) $18.6 $
Senior unsecured $30 million Canadian working capital revolving credit facility, bearing interest at a rate of 4.6% at September 30, 2004  11.4  
Senior unsecured $170 million Canadian revolving credit facility, bearing interest at a rate of 2.8% and 2.2% at September 30, 2004 and December 31, 2003, respectively  10.0  70.0
4.75% senior notes due August 2009, net of unamortized discount of $0.8 million at September 30, 2004  174.2  
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.3 million at September 30, 2004 and December 31, 2003, respectively  199.7  199.7
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million and $0.7 million at September 30, 2004 and December 31, 2003, respectively  249.4  249.3
5.88% senior notes due August 2016, net of unamortized discount of $1.1 million at September 30, 2004  173.9  
Other  0.4  
  
 
 Total long-term debt(1)(2)  837.6  519.0
  
 
Total debt $960.5 $646.3
  
 

(1)
At JuneSeptember 30, 2004 and December 31, 2003, we have classified $13.2$60.0 million and $25.3 million, respectively, of borrowings under our senior unsecured $425 million domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowings and primarily are for hedged LPG inventory and New York Mercantile Exchange margin deposits and must be repaid within one year.

(2)
At September 30, 2004, the aggregate fair value of our fixed rate senior notes was approximately $854.8 million.

        In connection with the Link acquisition, we entered into a new $200 million revolving credit facility that has a 364-day term and contains a twelve-month term out option, exercisable at our election, at the end of the primary term. We have classified amounts outstanding under this facility as long-term as we have both the intent and the ability to refinance these amounts into long-term borrowings. The facility bears interest at a rate of LIBOR plus a margin ranging from .625% to 1.25%, depending upon our credit rating, and includes essentially the same covenants as our existing credit facilities. We repaid approximately $160 million of amounts outstanding under this facility with proceeds from our third quarter 2004 equity offering, and have committed to use net proceeds from future debt and equity offerings to prepay indebtedness outstanding and reduce the commitment level. See Note 6.

        OnDuring August 5, 2004, we soldcompleted the sale of $175 million of 4.75% Senior Notes due 2009 and $175 million of 5.88% Senior Notes due 2016. The 4.75% notes were sold at 99.551% of face value and the 5.88% notes were sold at 99.345% of face value. The notes were co-issued by Plains All American


Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations). Interest payments are due on February 15 and August 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are minor. We expect to close the sale on August 12, 2004, with proceeds after initial purchaser discount and offering costs of approximately $345.3 million. We intend to useused the proceeds to



repay amounts outstanding under our credit facilities, including the remaining balance under the $200 million, 364-day facility we used to fund the Link acquisition,described above, and for general partnership purposes. In connection with this repayment, we terminated the facility. The repayment and termination of this facility resulted in a non-cash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs. Subsequent to the notes offering, we also terminated our $125 million, 364-day facility which was scheduled to expire in November 2004.

        We are inIn the processthird quarter of increasing the capacity of2004, we increased our uncommitted senior secured hedged inventory facility from $200 million to $300 million, primarily as a resultwith the ability to further increase the facility in the future by an incremental $200 million. This facility is an uncommitted working capital facility, which is used to finance the purchase of increasedhedged crude oil pricesinventory for storage when market conditions warrant. Borrowings under the hedged inventory facility are secured by the inventory purchased under the facility and an increasethe associated accounts receivable, and are repaid with the proceeds from the sale of such inventory. This facility expires in our crude oil storage capacity as a result of acquisitions. WeNovember 2004, and we expect to completeextend the increase during the third quarter.maturity to November 2005 before expiration.

        In November 2004, we entered into a new $750 million, five-year senior credit facility, which contains a sub-facility for Canadian borrowings up to $300 million. The new facility extends our maturities, lowers our cost of credit and provides an additional $125 million of liquidity over our previous facility. The facility can be expanded to $1 billion.



Note 5—6—Earnings Per Common Unit

        The following table sets forth the computation of basic and diluted earnings per limited partnercommon unit:

 
 Three months ended June 30,
 Six months ended June 30,
 
 
 2004
 2003
 2004
 2003
 
 
 (in thousands, except per unit data)

 
Net income $35,677 $23,398 $63,553 $47,749 
Less:             
 General partner incentive distributions  (1,752) (1,266) (3,396) (2,274)
 General partner 2% ownership  (678) (442) (1,203) (909)
  
 
 
 
 
Numerator: net income available for common unitholders $33,247 $21,690 $58,954 $44,566 
  
 
 
 
 
Denominator: weighted average number of limited partner units outstanding  61,556  52,223  59,985  51,200 
  
 
 
 
 
Basic and diluted net income per limited partner unit $0.54 $0.42 $0.98 $0.87 
  
 
 
 
 
 
 Three months ended September 30,
 Nine months ended September 30,
 
 
 2004
 2003
 2004
 2003
 
 
 (in thousands, except per unit data)

 
Net income $41,734 $11,871 $105,287 $59,620 
Less:             
 Incentive distribution right  (2,205) (1,266) (5,601) (3,540)
  
 
 
 
 
 Subtotal  39,529  10,605  99,686  56,080 
 General partner 2% ownership  (791) (213) (1,994) (1,122)
  
 
 
 
 
Numerator:             
Numerator for basic earnings per limited partner unit—             
 Net income available for limited partners  38,738  10,392  97,692  54,958 
Effect of dilutive securities:             
 Increase in incentive distribution right-contingent equity issuance    (16)   (46)
  
 
 
 
 
Numerator for diluted earnings per limited partner unit $38,738 $10,376 $97,692 $54,912 
  
 
 
 
 
Denominator:             
 Denominator for basic earnings per limited partner unit—weighted average number of limited partner units  65,776  52,788  61,929  51,735 
  
 
 
 
 
Effect of dilutive securities:             
 Contingent equity issuance    647    672 
  
 
 
 
 
Denominator for diluted earnings per limited partner unit  65,776  53,435  61,929  52,407 
  
 
 
 
 

Basic net income per limited partner unit

 

$

0.59

 

$

0.20

 

$

1.58

 

$

1.06

 
  
 
 
 
 
Diluted net income per limited partner unit $0.59 $0.19 $1.58 $1.05 
  
 
 
 
 

        In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 did not result in a change in the Partnership's earnings per limited partner unit for any of the periods presented.



Note 6—7—Partners' Capital and Distributions

        In November 2003, pursuant to the terms of our Partnership Agreement, 25% of our subordinated units converted to common units on a one-for-one basis. In February 2004, all of the remaining subordinated units converted to common units on a one-for-one basis.

        Long-Term Incentive Plan.    We issued approximately 138,000315,500 common units during the first quarterhalf of 2004 and approximately 177,50047,500 common units during the secondthird quarter of 2004 in conjunction with the vesting of awards under our Long-Term Incentive Plan ("LTIP"). In connection with such


issuances, the General Partner made a proportionalproportionate two percent contribution. See Note 78 for additional discussion.

        Payment of Deferred Acquisition Price.    In connection with the CANPET acquisition in July 2001, $26.5 million Canadian of the purchase price, payable in common units or cash at our option, was deferred subject to various performance objectives being met. These objectives were met as of December 31, 2003 and an increase to goodwill for this liability was recorded as of that date. The liability was satisfied onOn April 30, 2004, with the issuance ofwe issued approximately 385,000 common units and the payment ofpaid approximately $6.5 million in cash. Thecash to satisfy the contingent consideration related to the July 2001 CANPET acquisition. In accordance with the provisions of the purchase and sale agreement, the number of common units issued in satisfaction of the deferred payment was based upon $34.02 per share, the average trading price of our common units for the ten-day trading period prior to the payment date, and a Canadian dollar to U.S. dollar exchange rate of 1.35 to 1, the average noon-day exchange rate for the ten-day trading period prior to the payment date. In addition, an incremental $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition.

        Private Placement of Class C Common Units.    In connection with the Link acquisition, on April 15, 2004 we issued 3,245,700 Class C common units for $30.81 per unit in a private placement to a group of institutional investors comprisedconsisting of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors. Affiliates of both Kayne Anderson Capital Advisors and Vulcan Capital own interests in our general partner. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million, and were used to reduce the balance outstanding under our revolving credit facilities. The Class C common units are unlisted securities that arepari passu in voting and distribution rights with the Partnership's publicly traded common units. The Class C common units are similar in manymost respects to the Partnership's Class B common units. The Class C common units areBoth classes become convertible into common units upon approval by the holders of a majority of the common units. Beginning six months from the closingSee "—Class B and Class C Common; Unitholder Meeting."

        Class B and Class C Common; Unitholder Meeting.    Each of the private placement, theClass B common unitholders and Class C common unitholders may request that the Partnership call a meeting of its common unitholders to consider approval of a change in the conversionterms of the Class B units or Class C units, as applicable, to provide that those units may be converted at the option of the holder into common units. The holders of both the Class B common units and the Class C common units made such a request on October 18, 2004. If the approval of the conversioncommon unitholders is not obtained within 120 days of the request, the holders of the Class B and Class C unitholdersunits (unless and until converted into common units) will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit. If the approval of the conversioncommon unitholders is not secured within 90 days after the



end of the 120-day period, the distribution right increases to 115%. The holderPartnership is in the process of our Class B common units, Plains Holdings Inc., haspreparing for a similar right to request a unitholder meeting which is currently exercisable.of unitholders.

        Equity Offering.    In the third quarter of 2004, we completed a public offering of 4,904,0004,968,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $163.1$165.2 million from the sale of units and approximately $3.3$3.4 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.3$7.7 million. Net proceeds of $159.1$160.9 million were used to permanently reduce outstanding borrowings under the $200 million, 364-day credit facility (see Note 4)5).

        On July 21,October 22, 2004, we declared a cash distribution of $0.5775$0.60 per unit on our outstanding common units, Class B common units and Class C common units. The distribution is payable on August 13,November 12, 2004, to unitholders of record on August 3,November 2, 2004, for the period AprilJuly 1, 2004, through JuneSeptember 30, 2004. The total distribution to be paid is approximately $41.8$43.9 million, with approximately $38.8$40.4 million to be paid to our common unitholders and $0.8 million and $2.2$2.7 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

        On April 23,August 13, 2004, we declaredpaid a cash distribution of $0.5775 per unit on our outstanding common units, Class B common units and Class C common units, for the period April 1, 2004, through June 30, 2004. The total distribution paid was approximately $41.8 million, with approximately $38.8 million paid to our common unitholders and $0.8 million and $2.2 million paid to our general partner for its general partner and incentive distribution interests, respectively.

        On May 14, 2004, we paid a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and Class C common units. The distribution was paid on May 14, 2004, to unitholders of record on May 4, 2004,units, for the period January 1, 2004, through March 31, 2004. The



total distribution paid was approximately $37.5 million, with approximately $35.0 million paid to our common unitholders and $0.7 million and $1.8 million paid to our general partner for its general partner and incentive distribution interests, respectively.

        On January 22,February 13, 2004, we declaredpaid a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on February 13, 2004, to unitholders of record on February 3, 2004,units, for the period October 1, 2003, through December 31, 2003. The total distribution paid was approximately $35.2 million, with approximately $28.7 million paid to our common unitholders, $4.2 million paid to our subordinated unitholders and $0.7 million and $1.6 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Note 7—8—Vesting of Unit Grants Under Long-Term Incentive Plan

        During the first halfnine months of 2004, approximately 796,000895,000 phantom units vested. We paid cash in lieu of delivery of common units for approximately 306,000328,000 of the phantom units and issued approximately 315,500362,000 new common units (after netting for taxes) in connection with the remainder of the vesting.

        Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that phantom unit grants under our LTIP will vest. During the first halfnine months of



2004, we recognized $4.2 million of compensation expense related to the vesting of phantom units under the LTIP. This expense includes an anticipated vesting in August 2004. We will recognize additional expense when it is considered probable that additional vestings will occur. Generally, future vestings will occur when the annualized distribution rate reaches $2.50 and again at $2.70. We anticipate that, afterAfter giving effect to the Augustthird quarter 2004 vesting and related tax withholding and cash settlement, approximately 874,000 phantom units will beare available under the plan for future grant and approximately 140,000134,000 phantom units will remain outstanding. In accordance with the provisions of the LTIP and applicable NYSE standards, no more than approximately 564,000460,000 of such phantom unit grants (outstanding or future) could be satisfied by delivery of common units.

Note 8—9—Derivative Instruments and Hedging Activities

        We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities address our market risks. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

        The following is a summary of the financial impact of the derivative instruments and hedging activities discussed below. The JuneSeptember 30, 2004, balance sheet includes assets of $35.4$53.6 million ($27.739.5 million current), liabilities of $23.5$43.9 million ($16.332.8 million current) and unrealized net gains deferred to Other Comprehensive Income ("OCI") of $4.6$0.4 million. EarningsTotal derivative activities for the sixnine months ended JuneSeptember 30, 2004, includegenerated a gain of $10.7 million (including a gain$66.3 million. Total derivative activities include the mark-to-market of $7.1 millionopen positions that was reclassified intodo not meet hedge accounting requirements and gains and losses recognized in earnings from OCIfor all hedges settled during the period).period. The majority of these gains are related to our commodity price risk hedges that are offset by physical transactions, as discussed below.

        As of JuneSeptember 30, 2004, the total amount of deferred net lossesgains recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the sixnine months ended JuneSeptember 30, 2004, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $4.6$0.4 million net gain deferred in OCI at JuneSeptember 30, 2004, a net gain of $11.0$7.3 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals ending in 2013.2016. Since a portion of these amounts areis based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.



        The following sections discuss our risk management activities in the indicated categories.

        We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilizedwe use consist primarily of futures and option contracts traded on the NYMEX and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of the instruments that qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into OCI and recognized in revenues or cost of salescrude oil and operationsLPG purchases and related costs in the periods during which the underlying physical transactions occur. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

        Although we seek to maintain a position that is substantially balanced within our crude oil lease purchase activities, we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

        At JuneSeptember 30, 2004, we have no open interest rate hedging instruments. However, there isare approximately $5.4$6.5 million deferred in OCI that relates to instruments that were terminated and cash settled ($1.4 million related to an instrument settled in 2003.2004 and $5.1 million related to instruments settled in 2003). The net deferred loss related to these instruments is being amortized into interest expense over the original terms of the terminated instruments (approximately fiftyforty percent over threethe next two years and the remaining fiftysixty percent over approximately ten years). Approximately $0.7$1.1 million related to the terminated instruments has been reclassified into interest expense during the first halfnine months of 2004, and approximately $1.4$1.5 million will be reclassified for the entire year of 2004. In addition, earnings for the first halfnine months of 2004 include a loss of approximately $0.7 million that was reclassified out of OCI related to an instrument that matured in March 2004.


        Because a significant portion of our Canadian business is conducted in Canadian dollars and, at times, a portion of our debt is denominated in Canadian dollars, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts and cross currency swaps. The forward exchange contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133. Additionally, at times, a portion of our debt is denominated in Canadian dollars. At June 30, 2004, $4.0 million of our long-term debt was denominated in Canadian dollars ($5.3 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.33 to 1). All of these financial instruments are placed with what we believe to be large creditworthy financial institutions.


        At JuneSeptember 30, 2004, we had forward exchange contracts that allow us to exchange $2.0 million Canadian dollars for approximately $1.5 million U.S. dollars, quarterly, during 2004 and approximately $1.0 million Canadian for approximately $0.7 million U.S. quarterly during 2005 (based on a Canadian dollar to U.S. dollarat set exchange rate of 1.33 to 1 and 1.34 to 1, respectively).rates as detailed below:

 
 Canadian
Dollars

 US
Dollars

 Rate
 
 ($ in millions)

  
2004 $5.0 $3.8 1.32 to 1
2005 $3.0 $2.3 1.33 to 1
2006 $2.0 $1.5 1.32 to 1

        In addition, at JuneSeptember 30, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $21.0 million, effectively converting this amount of our U.S. dollar denominated debt to $32.5 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduceswill reduce by $2.0 million U.S. in May 2005 and has a final maturity in May 2006 of $19.0 million U.S. At September 30, 2004, $6.2 million of our long-term debt was denominated in Canadian dollars ($7.8 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.26 to 1). All of these financial instruments are placed with what we believe to be large, creditworthy financial institutions.

Note 9—10—Commitments and Contingencies

Litigation

        Export License Matter.    In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, weWe have received a request from the BIS for additional information.information, which we are in the process of providing. At this time, we have received no indication whether the BIS intends to charge us with a violation of


the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of this matter.

        General.    We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Environmental

        We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. At JuneSeptember 30, 2004, our reserve for environmental liabilities totaled approximately $23.5$21.4 million. Approximately $15.7$13.8 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

Other

        The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and



retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

Note 10—11—Operating Segments

        Our operations consist of two operating segments: (1) Pipeline Operations—engagesOperations, which engage in interstate and intrastate crude oil pipeline transportation and certain related merchantmargin activities; and (2) Gathering, Marketing, Terminalling and Storage Operations—engagesOperations, which engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow.



        We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs, and (iii) segment general and administrative expenses. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to 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. The following table reflects our results of operations for each segment



for the periods indicated (note that each of the items in the following table excludes depreciation and amortization):



 Pipeline
 Gathering,
Marketing,
Terminalling
& Storage

 Total
 
 Pipeline
 GMT&S
 Total
 


 (in millions)

 
 (in millions)

 
Three Months Ended June 30, 2004       
Three Months Ended September 30, 2004Three Months Ended September 30, 2004       
Revenues:Revenues:       Revenues:       
External Customers $190.7 $4,941.1 $5,131.8 External Customers $192.3 $5,674.7 $5,867.0 
Intersegment(1) 32.1 0.2 32.3 Intersegment(1) 35.1 0.3 35.4 
 
 
 
   
 
 
 
 Total revenues of reportable segments $222.8 $4,941.3 $5,164.1  Total revenues of reportable segments $227.4 $5,675.0 $5,902.4 
 
 
 
   
 
 
 
Segment profitSegment profit $47.7 $13.5 $61.2 Segment profit $44.0 $27.3 $71.3 
 
 
 
   
 
 
 
Non-cash SFAS 133 impact(2)Non-cash SFAS 133 impact(2) $ $(6.9)$(6.9)Non-cash SFAS 133 impact(2) $ $0.9 $0.9 
 
 
 
   
 
 
 
Maintenance capitalMaintenance capital $0.6 $0.7 $1.3 Maintenance capital $2.0 $1.0 $3.0 
 
 
 
   
 
 
 

Three Months Ended June 30, 2003

 

 

 

 

 

 

 
Three Months Ended September 30, 2003Three Months Ended September 30, 2003       
Revenues:Revenues:       Revenues:       
External Customers $143.3 $2,565.9 $2,709.2 External Customers $148.3 $2,905.3 $3,053.6 
Intersegment(1) 12.5 0.3 12.8 Intersegment(1) 16.1 0.2 16.3 
 
 
 
   
 
 
 
 Total revenues of reportable segments $155.8 $2,566.2 $2,722.0  Total revenues of reportable segments $164.4 $2,905.5 $3,069.9 
 
 
 
   
 
 
 
Segment profitSegment profit $24.2 $18.9 $43.1 Segment profit $22.9 $9.6 $32.5 
 
 
 
   
 
 
 
Non-cash SFAS 133 impact(2)Non-cash SFAS 133 impact(2) $ $0.2 $0.2 Non-cash SFAS 133 impact(2) $ $(2.9)$(2.9)
 
 
 
   
 
 
 
Maintenance capitalMaintenance capital $2.4 $0.2 $2.6 Maintenance capital $1.0 $0.3 $1.3 
 
 
 
   
 
 
 



 Pipeline
 Gathering,
Marketing,
Terminalling
& Storage

 Total

 Pipeline
 GMT&S
 Total
 


 (in millions)


 (in millions)

 
Six Months Ended June 30, 2004      
Nine Months Ended September 30, 2004Nine Months Ended September 30, 2004       
Revenues:Revenues:       
External Customers $556.5 $14,246.9 $14,803.4 
Intersegment(1) 83.0 0.7 83.7 
 
 
 
 
 Total revenues of reportable segments $639.5 $14,247.6 $14,887.1 
 
 
 
 
Segment profitSegment profit $117.2 $68.9 $186.1 
 
 
 
 
 Total assets $1,100.5 $2,005.5 $3,106.0 
 
 
 
 
Non-cash SFAS 133 impact(2)Non-cash SFAS 133 impact(2) $ $1.4 $1.4 
 
 
 
 
Maintenance capitalMaintenance capital $4.1 $2.0 $6.1 
 
 
 
 
Nine Months Ended September 30, 2003Nine Months Ended September 30, 2003       
Revenues:Revenues:      Revenues:       
External Customers $364.2 $8,572.2 $8,936.4External Customers $450.6 $8,594.1 $9,044.7 
Intersegment(1) 47.9 0.4 48.3Intersegment(1) 38.5 0.7 39.2 
 
 
 
 
 
 
 
 Total revenues of reportable segments $412.1 $8,572.6 $8,984.7 Total revenues of reportable segments $489.1 $8,594.8 $9,083.9 
 
 
 
 
 
 
 
Segment profitSegment profit $73.2 $41.6 $114.8Segment profit $67.2 $52.9 $120.1 
 
 
 
 
 
 
 
Non-cash SFAS 133 impact(2)Non-cash SFAS 133 impact(2) $ $0.5 $0.5Non-cash SFAS 133 impact(2) $ $(1.7)$(1.7)
 
 
 
 
 
 
 
Maintenance capitalMaintenance capital $2.1 $1.0 $3.1Maintenance capital $4.8 $0.7 $5.5 
 
 
 
 
 
 
 

Six Months Ended June 30, 2003

 

 

 

 

 

 
Revenues:      
External Customers $302.3 $5,688.8 $5,991.1
Intersegment(1) 22.5 0.5 23.0
 
 
 
 Total revenues of reportable segments $324.8 $5,689.3 $6,014.1
 
 
 
Segment profit $44.4 $43.3 $87.7
 
 
 
Non-cash SFAS 133 impact(2) $ $1.1 $1.1
 
 
 
Maintenance capital $3.8 $0.4 $4.2
 
 
 

(1)
Intersegment sales are conducted at arms length.

(2)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

        The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle (in millions):principle:


 For the three
months ended
September 30,

 For the nine
months ended
September 30,

 

 For the three months
ended June 30,

 For the six months
ended June 30,

  2004
 2003
 2004
 2003
 

 2004
 2003
 2004
 2003
  (in millions)

 
Segment profit $61.2 $43.1 $114.8 $87.7  $71.3 $32.5 $186.1 $120.1 
Depreciation and amortization (16.0) (11.3) (29.1) (22.2)  (16.8) (12.0) (45.9) (34.2)
Interest expense (10.0) (8.5) (19.5) (17.7)  (12.7) (8.8) (32.2) (26.5)
Interest income and other, net 0.5 0.1 0.5 (0.1)  (0.1) 0.1  0.4  0.2 
 
 
 
 
  
 
 
 
 
Income before cumulative effect of change in accounting principle $35.7 $23.4 $66.7 $47.7  $41.7 $11.8 $108.4 $59.6 
 
 
 
 
  
 
 
 
 


Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

        The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes. For more detailed information regarding the basis of presentation for the following financial information, see the "Notes to the Consolidated Financial Statements." Our discussion and analysis includes the following:

Executive Summary

Company Overview—Plains All American Pipeline, L.P. is a Delaware limited partnership (the "Partnership") formed in September of 1998. Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. (formerly known as All American Pipeline, L.P.) and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." We own an extensive network in the United States and Canada of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs.hubs in the United States and Canada.

        We are one of the largest midstream crude oil companies in North America, with over 14,000America. As of September 30, 2004, we owned approximately 15,000 miles of crude oil pipelines, approximately 37.037 million barrels of terminalling and storage capacity and a full complement of truck transportation and injection assets. On average,Currently, we handle an average of over 2.62.5 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada. Our operations are conducted primarily in Texas, Oklahoma, California, Louisiana, Kansas and the Canadian provinces of Alberta and Saskatchewan and consist of two operating segments: (i) pipeline operations and (ii) gathering, marketing, terminalling and storage operations ("GMT&S"). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets.

        SecondThird Quarter 2004 Operating Results Overview—During the secondthird quarter of 2004, we recognized net income of $41.7 million and earnings per limited partner unit of $35.7 million and $0.54, respectively,$0.59, both of which was a 52% and 29% increase, respectively,were substantial increases over the secondresults of the third quarter of 2003. The primary drivers of the increase in current quarter results forover the second quarter of 2004 compared to the secondthird quarter of 2003 include significant contributions fromwere:



        The impact of the items discussed above resulted in segment profit per barrel calculated(calculated based on our lease gathered crude oil and LPG barrels was $0.23barrels) of $0.46 per barrel for the quarter ended JuneSeptember 30, 2004, compared to $0.48$0.23 for the quarter ended JuneSeptember 30, 2003. The inclusion of the non-cash mark-to-market loss of $6.9 million resulted in a decrease in the segment profit per barrel for the second quarter of 2004 of approximately $0.16. Additionally, segment profit per barrel was negatively impacted by lower segment profit per barrel on the lease gathered barrels added in the 2004 quarter from the Link acquisition. Per barrel profits related to the Link acquisition are lower as the gathering business primarily supported the pipeline operations.

        Revenues from our GMT&S operations were approximately $4.9 billion and $2.6 billion for the quarters ended June 30, 2004 and 2003, respectively. As discussed above, revenues and costs related to purchases for the 2004 period were impacted by higher average prices and higher volumes as compared



to the 2003 period. The average NYMEX price for crude oil was $38.28 per barrel and $28.96 per barrel for the quarter ended June 30, 2004 and 2003, respectively.

Other Expenses

        Depreciation and amortization expense was $16.0$16.8 million for the three months ended JuneSeptember 30, 2004, compared to $11.3$12.0 million for the three months ended JuneSeptember 30, 2003. The increase relates primarily to the assets from our 2004 acquisitions and our various 2003 acquisitions being included for the full quarter in 2004 versus only a part or none of the quarter in 2003. Additionally, several capital projects were completed during mid-to-late 2003 that were not included in secondthird quarter 2003 depreciation expense. Amortization of debt issue costs was $0.7 million and $1.0 million in the secondthird quarter of 2004 and 2003, respectively.

        The amount of interest expense we recognize is primarily impacted by our average debt balances, the level and maturity of fixed rate debt and interest rates associated therewith, market interest rates and our interest rate hedging activities on floating rate debt. During the secondthird quarter of 2004, our average debt balance was approximately $943$899 million. This balance consisted of fixed rate senior notes with a face amount totaling $450


averaging $640 million and borrowings under our revolving credit facilities averaging $493$259 million. During the comparable 2003 period, our average debt balance was approximately $515$532 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of $315$332 million. The higher average debt balance in the 2004 period was primarily related to the portion of our acquisitions that were not refinanced with equity. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity.

        During the fourth quarter of 2003, we refinanced our senior secured credit facilities with new senior unsecured credit facilities, issued $250 million of ten year senior unsecured notes and terminated interest rate hedging instruments with notional amounts totaling $150 million. The termination of these instruments was made in connection with the issuance of the ten-year notes. During the third quarter of 2004, we issued $175 million of five year senior unsecured notes and $175 million of twelve year senior unsecured notes. The net result of the changes to our debt structure and our interest rate hedging instruments was an increase in the average amount of fixed rate debt outstanding in the secondthird quarter of 2004 to approximately 48%72% as compared to approximately 39%38% in the secondthird quarter of 2003. The new senior unsecuredrefinancing of our credit facilities in the fourth quarter 2003 reduced the interest rate on our credit facilities by approximately 100 basis points compared to the senior secured facility. In addition, during these two periods the average three-month LIBOR rate rose to 1.3%1.8% in 2004 from 1.2%1.1% in 2003.

        The net impact of the items discussed above was an increase in interest expense in the secondthird quarter of 2004 of approximately $1.5$3.9 million to a total of $10.0$12.7 million. The higher average debt balance in the 2004 period resulted in additional interest expense of approximately $4.6$4.9 million, while at the same time our commitment and other fees decreased by approximately $0.6$0.2 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 4.2%5.3% for the 2004 period compared to 6.1%5.9% for the 2003 period. The lower weighted average rate decreased interest expense by approximately $2.5$0.8 million in the secondthird quarter of 2004 compared to the secondthird quarter of 2003.


        During the third quarter of 2004, we completed (i) the issuance of 4,968,000 common units and (ii) the issuance of an aggregate of $350 million of senior secured notes. We used the proceeds from these issuances to, among other things, repay amounts outstanding under our revolving credit facilities, including all amounts outstanding under the $200 million, 364-day facility we used to fund the Link acquisition. The repayment and termination of this facility resulted in a non-cash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs.

        For the sixnine months ended JuneSeptember 30, 2004, we reported consolidated net income of $63.6$105.3 million on total revenues of $8.9$14.8 billion compared to net income for the same period in 2003 of $47.7$59.6 million on total revenues of $6.0$9.0 billion. The following table reflects our results of operations


and maintenance capital for each segment (note that each of the items in the following table excludes depreciation and amortization):


 Pipeline
 GMT&S
  Pipeline
 GMT&S
 

 (in millions)

  (in millions)

 
Six Months Ended June 30, 2004(1)     
Nine Months Ended September 30, 2004(1)     
Revenues $412.1 $8,572.6  $639.5 $14,247.6 
Purchases (269.6) (8,464.2) (408.4) (14,075.8)
Field operating costs (excluding LTIP charge) (51.2) (45.7) (84.8) (73.3)
LTIP charge—operations (0.1) (0.4) (0.1) (0.4)
Segment G&A expenses (excluding LTIP charge)(2) (16.3) (18.7) (27.3) (27.2)
LTIP charge—general and administrative (1.7) (2.0) (1.7) (2.0)
 
 
  
 
 
Segment profit $73.2 $41.6  $117.2 $68.9 
 
 
  
 
 
Noncash SFAS 133 impact(3) $ $0.5  $ $1.4 
 
 
  
 
 
Maintenance capital $2.1 $1.0  $4.1 $2.0 
 
 
  
 
 

Six Months Ended June 30, 2003(1)

 

 

 

 

 
Nine Months Ended September 30, 2003(1)     
Revenues $324.8 $5,689.3  $489.1 $8,594.8 
Purchases (243.6) (5,591.9) (362.9) (8,457.2)
Field operating costs (27.7) (38.0)
Segment G&A expenses(2) (9.1) (16.1)
Field operating costs (excluding LTIP charge) (42.3) (56.6)
LTIP charge—operations (0.4) (1.0)
Segment G&A expenses (excluding LTIP charge)(2) (13.7) (23.7)
LTIP charge—general and administrative (2.6) (3.4)
 
 
  
 
 
Segment profit $44.4 $43.3  $67.2 $52.9 
 
 
  
 
 
Noncash SFAS 133 impact(3) $ $1.1  $ $(1.7)
 
 
  
 
 
Maintenance capital $3.8 $0.4  $4.8 $0.7 
 
 
  
 
 

(1)
Revenues and purchases include intersegment amounts.

(2)
Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

Pipeline Operations

        The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:



 Six months ended June 30,
 
 Nine months ended
September 30,

 


 2004
 2003
 
 2004
 2003
 
Operating Results(1) (in millions)Operating Results(1) (in millions)     Operating Results(1) (in millions)     
Revenues     Revenues     
 Tariff activities $130.9 $72.1  Tariff activities $215.3 $112.4 
 Pipeline margin activities 281.2 252.7  Pipeline margin activities 424.2 376.7 
 
 
   
 
 
Total pipeline operations revenues 412.1 324.8 Total pipeline operations revenues 639.5 489.1 

Costs and Expenses

 

 

 

 

 
Costs and Expenses     
 Pipeline margin activities purchases (269.6) (243.6) Pipeline margin activities purchases (408.4) (362.9)
 Field operating costs (excluding LTIP charge) (51.2) (27.7) Field operating costs (excluding LTIP charge) (84.8) (42.3)
 LTIP charge—operations (0.1)   LTIP charge—operations (0.1) (0.4)
Segment G&A expenses (excluding LTIP charge)(2) (16.3) (9.1) Segment G&A expenses (excluding LTIP charge)(2) (27.3) (13.7)
LTIP charge—general and administrative (1.7)   LTIP charge—general and administrative (1.7) (2.6)
 
 
   
 
 
Segment profit $73.2 $44.4 Segment profit $117.2 $67.2 
 
 
   
 
 
Maintenance capital $2.1 $3.8 Maintenance capital $4.1 $4.8 
 
 
   
 
 

Average Daily Volumes (thousands of barrels per day)(3)

Average Daily Volumes (thousands of barrels per day)(3)

 

 

 

 

 
Average Daily Volumes (thousands of barrels per day)(3)     
Tariff activities     Tariff activities     
 All American 57 61  All American 55 60 
 Basin 273 245  Basin 275 264 
 Link acquisition 185   Link acquisition 248 N/A 
 Capline 112   Capline 115 N/A 
 Other domestic 408 261  Other domestic 420 283 
 Canada 250 181  Canada 257 191 
 
 
   
 
 
Total tariff activities 1,285 748 Total tariff activities 1,370 798 
Pipeline margin activities 73 81 Pipeline margin activities 72 80 
 
 
   
 
 
 Total 1,358 829  Total 1,442 878 
 
 
   
 
 

(1)
Revenues and purchases include intersegment amounts.

(2)
Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

        Total average daily volumes transported were approximately 1.4 million barrels per day and 0.8 million barrels per day for the six months ended June 30, 2004 and 2003, respectively. The increase relates to our tariff activities. As discussed above, we have completed a number of acquisitions during



2004 and 2003 that have impacted the results of operations. The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes:

 
 Six months ended
June 30,

 
 2004
 2003
 
 (thousands of barrels per day)

Tariff activities(1)    
 2004 acquisitions 396 
 2003 acquisitions 166 33
 All other pipeline systems 723 715
  
 
 Total tariff activities average daily volumes 1,285 748
  
 

(1)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

        Average daily volumes from our tariff activities increased 0.5 million barrels per day to approximately 1.3 million barrels per day. Almost all of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2004 and 2003. Volumes on all other pipeline systems were relatively unchanged.

        Total revenues from our pipeline operations were approximately $412.1$639.5 million and $324.8$489.1 million for the sixnine months ended JuneSeptember 30, 2004 and 2003, respectively. An increase in revenues from tariff activities accounted for $58.8$102.9 million of the increase.increase (see discussion below). Additionally, revenues from our margin activities increased by approximately $28.5$47.5 million in the first half of 2004.2004 period. This increase was related to higher average prices for crude oil sold and transported on our SJV gathering system in the 2004 period as compared to the 2003 period, partially offset by lower buy/sell volumes. BecauseAs mentioned above, because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. Volumes transported on the SJV system have decreased from the 2003 period. This is primarily related to a normalizing of volumes transported in(i) the first quarter of 2004 as the first quarter of



2003 includedincluding additional shipments that typically move on other pipelines. These volumes shiftedpipelines and (ii) the use by refineries of foreign crude oil instead of crude oil transported on the SJV system.

        Segment profit, our primary measure of segment performance, increased approximately 74% to $117.2 million for the nine months ended September 30, 2004 as compared to the SJV system2003 period. The primary drivers impacting the 2004 period as compared to the 2003 period are:

        As discussed above, the increase in pipeline operations segment profit is largely related to our acquisition activities. We have completed a number of acquisitions during 2004 and 2003 that have impacted the results of operations herein. The following table reflects ourpresentation helps summarizes the impact of recent acquisitions on volumes and revenues fromrelated to our tariff activities by year of acquisition for comparison purposes:activities.

 
 Six months ended
June 30,

 
 2004
 2003
 
 (in millions)

Tariff activities revenues(1)      
 2004 acquisitions $41.9 $
 2003 acquisitions  17.3  4.0
 All other pipeline systems  71.7  68.1
  
 
 Total tariff activities $130.9 $72.1
  
 
 
 Nine months ended September 30,
 
 2004
 2003
 
 Volumes
 Revenues
 Volumes
 Revenues
 
 (volume in thousands of barrels per day and revenues in millions)

Tariff activities(1)(2)          
 2004 Acquisitions 471 $77.7   
 2003 Acquisitions 168  27.7 58  8.0
 All other pipeline systems 731  109.9 740  104.4
  
 
 
 
Total tariff activities 1,370 $215.3 798 $112.4
  
 
 
 

(1)
Revenues include intersegment amounts.

(2)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

        Average daily volumes from our tariff activities increased 72% to approximately 1.4 million barrels per day and revenues from our tariff activities increased 92% to $215.3 million. The increase in the first halfthird quarter of 2004 is predominately related to (i) the inclusion of $26.6an average of 248 thousand barrels per day and $52.7 million of revenues from the pipelines acquired in the Link acquisition and $15.3(ii) 223 thousand barrels per day and $25.0 million of revenues from other businesses acquired in 2004.



businesses acquired in 2004. RevenuesVolumes from pipeline systems acquired in 2003 have increased to $17.3an average of 168 thousand barrels per day from an average of 58 thousand barrels per day, while related revenues increased to $27.7 million from $4.0$8.0 million. The increase is primarily the result of the inclusion in the first half of 2004 of several pipeline systems in the 2004 period that were acquired during or after or during the first half of 2003. See "Acquisition Activities." Revenues2003 (See "Acquisitions") coupled with higher realized prices on our loss allowance oil. Volumes and revenues from all other pipeline systems increased approximately $3.6 million to $71.7 million. The increase is primarily related to increased volumes on our Basin pipeline system and a $1.4 million favorable impact resulting from the decrease in the Canadian dollar to U.S. dollar exchange rate to an average of 1.34 to 1 for the first half of 2004, from an average of 1.45 to 1 for the first half of 2003.

        Field operating costs increased to $51.3 million in the first half of 2004 from $27.7 million in the first half of 2003. This increase is predominately related to our continued growth, primarily from acquisitions, and is comprised primarily of higher payroll and utility costs.

        Segment G&A expenses increased approximately $8.9 millionwere relatively flat between comparable periods, primarily as a result of our Link acquisition along with a $1.7 million accrual related to the probable vesting of unit grants under our Long-Term Incentive Plan ("LTIP"). G&A costs have also increased because of increased headcount resulting from continued growth and higher costs related to Sarbanes-Oxley requirements. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2004 period as our pipeline operations have grown. Including the impact of the items discussed above, segment profit was approximately $73.2 million for the six months ended June 30, 2004, an increase of 65% as compared to the $44.4 million reported for the six months ended June 30, 2003. Segment profit includes a $0.8 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2004 period as compared to the 2003 period.years.

Gathering, Marketing, Terminalling and Storage Operations

        Our revenues from gathering and marketing activities increased approximately 51% in the first half of 2004 compared to the first half of 2003, while our segment profit decreased approximately 3% in the same period. Approximately 55% of the increase in revenues related to increased sales volumes and the remaining 45% of the increase resulted from higher average prices in the 2004 period. The increase in sales volume primarily related to increased lease gathered barrels resulting primarily from the Link acquisition.

        During the first half of 2004, market conditions were generally favorable as the market was in relatively strong backwardation and experienced periods of volatility. The NYMEX benchmark price of crude ranged from $42.38 to $32.20 during the period. The market conditions in the first half of 2003 were more favorable as there was relatively high volatility and strong backwardation throughout the period. Additionally, cold weather during the first quarter of 2003 resulted in increased sales and higher margins in our LPG activities. During the first half of 2003, the NYMEX benchmark price of



crude oil ranged from $39.99 to $25.04.        The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated:



 Six months ended
June 30,

 
 Nine months ended
September 30,

 


 2004
 2003
 
 2004
 2003
 
Operating Results(1) (in millions)Operating Results(1) (in millions)     Operating Results(1) (in millions)     
Revenues $8,572.6 $5,689.3 Revenues $14,247.6 $8,594.8 
Purchases and related costs (8,464.2) (5,591.9)Purchases and related costs (14,075.8) (8,457.2)
Field operating costs (excluding LTIP charge) (45.7) (38.0)Field operating costs (excluding LTIP charge) (73.3) (56.6)
LTIP charge—operations (0.4)  LTIP charge—operations (0.4) (1.0)
Segment G&A expenses (excluding LTIP charge)(2) (18.7) (16.1)Segment G&A expenses (excluding LTIP charge)(2) (27.2) (23.7)
LTIP charge—general and administrative (2.0)  LTIP charge—general and administrative (2.0) (3.4)
 
 
   
 
 
Segment profit $41.6 $43.3 Segment profit $68.9 $52.9 
 
 
   
 
 
Noncash SFAS 133 impact(3) $0.5 $1.1 Noncash SFAS 133 impact(3) $1.4 $(1.7)
 
 
   
 
 
Maintenance capital $1.0 $0.4 Maintenance capital $2.0 $0.7 
 
 
   
 
 
Average Daily Volumes (thousands of barrels per day)(4)Average Daily Volumes (thousands of barrels per day)(4)     Average Daily Volumes (thousands of barrels per day)(4)     
Crude oil lease gatheringCrude oil lease gathering 550 430 Crude oil lease gathering 576 430 
Crude oil bulk purchasesCrude oil bulk purchases 135 78 Crude oil bulk purchases 143 84 
 
 
   
 
 
Total 685 508 Total 719 514 
 
 
   
 
 
LPG sales(5)LPG sales(5) 40 35 LPG sales(5) 39 31 
 
 
   
 
 

(1)
Revenues and purchases and related costs include intersegment amounts.

(2)
Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

(4)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

(5)
Prior period volumes have been adjusted for consistency of comparison between years. Sales reflect only third party volumes.

        Additionally, field operating costsAs discussed above, because the commodities that we buy and segment G&A expenses both increased during the period. Field operating costs increased to approximately $46.1 million in the current period from $38.0 million in the prior year period. This increase is primarily relatedsell are generally indexed to the Link acquisition. Also included is an approximately $0.4 million LTIP charge insame pricing indices for both the 2004 period. Segment G&A expenses increased to $20.7 million inpurchase and the current period from $16.1 million in the 2003 period. The increase is primarily related to the inclusion of the $2.0 million LTIP charge in the 2004 periodsale, revenues and increased headcount from continued growth and higher costs related to Sarbanes-Oxley requirements, but is partially offset by lower costs being allocatedpurchases will increase and decrease with changes in market prices. However, the margins related to our GMT&S segment as our Pipeline Operations segment continues to growthose purchases and commensurate with support activities provided to the pipeline operations by personnel predominantly involvedsales will not necessarily have corresponding increases and decreases. Our revenues increased approximately 66% in lease gathering activities.

        The crude oil volumes gathered from producers, using our assets or third-party assets, has increased by 28% during the first half of 2004. The increase is related to the Link acquisition and organic growth and other acquisitions, which has offset natural production declines. In addition, we marketed 40,000 barrels per day of LPG during the first sixnine months of 2004 compared to 35,000 barrels per daythe first nine months of 2003, while our segment profit increased approximately 30% in the first six months of 2003. Segment profit per barrel calculated based on our lease gathered crude oil and LPG sales volumes was $0.39 per barrel for the six months ended June 30, 2004, compared to $0.52 for the six months ended June 30, 2003. The impact of change in the non-cash



SFAS 133 mark-to-market for the first half of 2004 as compared to the first half of 2003 was a decrease in segment profit per barrel of approximately $0.02. Additionally, segment profit per barrel was negatively impacted by lower segment profit per barrel on the lease gathered barrels added in the 2004 quarter from the Link acquisition. Per barrel profits related to the Link acquisition are lower because the gathering business primarily supported the pipeline operations.

same period. Revenues from our gathering, marketing, terminalling and storageGMT&S operations were approximately $8.6$14.2 billion and $5.7$8.6 billion for the sixnine months ended JuneSeptember 30, 2004 and 2003, respectively. As discussed above, revenuesRevenues and costs related to purchases for the 2004 period were impacted by higher average prices and higher volumes as compared to the 2003 period. Approximately



52% of the increase in revenues resulted from higher average prices in the 2004 period and the remainder was attributable to increased sales volumes. The average NYMEX price for crude oil was $36.78$39.09 per barrel and $31.42$31.03 per barrel for the sixnine months ended JuneSeptember 30, 2004 and 2003, respectively.

        Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. Although we believe that the combination of our lease gathering business and our storage assets provides a counter-cyclical balance that provides stability in our margins, these margins are not fixed and may vary from period to period. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit (ii) crude oil lease gathered volumes and LPG sales volumes and (iii) segment profit per barrel calculated on these volumes.

        Segment profit increased approximately 30% to $68.9 million for the first nine months of 2004 as compared to the first nine months of 2003. The primary drivers for the increase in the current year were:


        The impact of the items discussed above resulted in segment profit per barrel (calculated based on our lease gathered crude oil and LPG barrels) of $0.41 per barrel for the nine months ended September 30, 2004, compared to $0.42 for the nine months ended September 30, 2003.

Other Expenses

        Depreciation and amortization expense was $29.1$45.9 million for the sixnine months ended JuneSeptember 30, 2004, compared to $22.2$34.2 million for the sixnine months ended JuneSeptember 30, 2003. The increase relates primarily to the assets from our 2004 acquisitions and our various 2003 acquisitions being included for the full sixnine months in 2004 versus only a part or none of the sixnine months in 2003. Additionally, several capital projects were completed during mid-to-latelate 2003 that were not included in the first sixnine months of 2003 depreciation expense. Amortization of debt issue costs was $1.2$1.9 million and $2.0$3.0 million in the first halfnine months of 2004 and 2003, respectively.

        During the first halfnine months of 2004, our average debt balance was approximately $771$719 million. This balance consisted of fixed rate senior notes with a face amount totaling $450averaging $514 million and borrowings under our revolving credit facilities averaging $321$205 million. During the comparable 2003 period, our average debt balance was approximately $520$525 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of $320$325 million. The higher average debt balance in the 2004 period was primarily related to the portion of our acquisitions that were not refinanced with equity. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity.

        The net result of the changes to our debt structure and our interest rate hedging instruments mentioned above wasresulted in an increase in the average amount of fixed rate debt outstanding in the first halfnine months of 2004 to approximately 58%72% as compared to approximately 38% in the first halfnine months of 2003. The new senior unsecured credit facilities reduced the interest rate on our credit facilities by approximately 100 basis points compared to the senior secured facility. In addition, during these two periods the average three-month LIBOR rate declinedrose to 1.2%1.4% in 2004 from 1.3%1.1% in 2003.

        The net impact of the items discussed above was an increase in interest expense infor the first half ofnine months ended 2004 of approximately $1.8$5.7 million to a total of $19.5$32.2 million. The higher average debt balance in the 2004 period resulted in additional interest expense of approximately $6.2$8.3 million, while at the same time our commitment and other fees decreased by approximately $1.4$1.6 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 4.9%5.7% for the first half ofnine months ended 2004 compared to 6.1%6.0% for the first half ofnine months ended 2003. The lower weighted average rate decreased interest expense by approximately $3.0$1.0 million induring the first half ofnine months ended 2004 compared to the first halfnine months ended 2003.

Other

        During the third quarter of 2003.2004, we completed (i) the issuance of 4,968,000 common units and (ii) the issuance of an aggregate of $350 million of senior secured notes. We used the proceeds from these issuances to, among other things, repay amounts outstanding under our revolving credit facilities, including all amounts outstanding under the $200 million, 364-day facility we used to fund the Link acquisition. The repayment and termination of this facility resulted in a non-cash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs.



Outlook

        This "Outlook" section and the section captioned "Forward Looking Statements and Associated Risks" identify certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future.

        Ongoing Acquisition Activities.    Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets.transportation, gathering, terminalling or storage assets and related businesses. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management has also expanded its efforts to encompass businesses that are closely related to, or significantly intertwined with, the crude oil business. We can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

        Link Energy LLC Acquisition.    The completion and integration of the Link acquisition began impacting our operating results in the second quarter of 2004. We anticipate that the assets acquired in the acquisition will generate a baseline cash flow from operations of approximately $6.25 million per quarter or approximately $25.0 million annually. In addition, we believe that we will realize annual cost savings and synergies of approximately $27.0 million to $32.0 million that are expected to be phased in by the first quarter of 2005 as the business is fully integrated. However, we also anticipate certain one-time expense items in the initial six to nine month period as a result of integration costs, as well as costs associated with regulatory requirements. These costs will have a negative impact in the short-term on our baseline projection for the acquisition.

Credit Rating.    In July 2004, Standard & Poor's removed us from creditwatch with negative implications and affirmed their BBB- stable senior unsecured rating (an investment grade rating). Also in JulyIn September 2004, Moody's Investors Service revisedcompleted their review ofand upgraded our senior unsecured rating fromto Baa3 with a review with direction uncertain to a review for possible upgrade. We are currently rated Ba1, which is Moody's highest non-investmentstable outlook (an investment grade rating.rating). You should note that a credit rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time.

Liquidity and Capital Resources

        Cash generated from operations and our credit facilities are our primary sources of liquidity. At JuneSeptember 30, 2004, we had a working capital deficit of approximately $26.2$50.5 million, approximately $342.6$401.1 million of availability under our committed revolving credit facilities and $168.0$240.5 million of unused capacity under our uncommitted hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.

        As discussed above, we closed the Link acquisition on April 1, 2004. The acquisition was funded with cash on hand, borrowings under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities. The new credit facility contains a twelve-month term out option, exercisable at our election, at the end of the primary term and bears interest at a rate of LIBOR plus a margin ranging from .625% to 1.25%, depending on our credit rating. In connection with the Link acquisition, on April 15, 2004, we completed the private placement of 3,245,700 units of Class C common units to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, was approximately $101 million, and was used to reduce the balance outstanding under our existing revolving credit facilities. We have committed to use net proceeds from future debt and equity offerings to retire or reduce the amount outstanding under the new $200 million, 364-day credit facility.



In the third quarter of 2004, we completed a public offering of 4,904,0004,968,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $163.1$165.2 million from the sale of units and approximately $3.3$3.4 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.3$7.7 million. Net proceeds of $159.1$160.9 million were used to permanently reduce outstanding borrowings under the new $200 million, 364-day credit facility as discussed above (see Note 4).facility.

        On August 5,12, 2004, we sold $175 million of 4.75% Senior Notessenior notes due 2009 and $175 million of 5.88% Senior Notessenior notes due 2016. The 4.75% notes were sold at 99.551% of face value and the 5.88% notes were sold at 99.345% of face value. We expect to closeused the sale on August 12, 2004, withnet proceeds, after deducting initial purchaser discountdiscounts and offering costs, of approximately $345.3 million. We intend to use the proceedsmillion to repay amounts outstanding under our credit facilities, including the remaining balance under the $200 million, 364-day facility we used to fund the Link acquisition, and for general partnership purposes. In connection with this repayment, we terminated the facility. Subsequent to the notes offering, we also terminated our $125 million, 364-day facility, which was scheduled to expire in November 2004.

        We are inIn the processthird quarter of increasing2004, we increased the capacity of our uncommitted senior secured hedged inventory facility from $200 million to $300 million (with the ability to further increase the facility in the future by an incremental $200 million), primarily as a result of increased crude oil prices and an increase in our crude oil storage capacity as a result of acquisitions. WeThis facility expires in November 2004, and we expect to completeextend the increase during the third quarter.maturity to November 2005 before expiration.



        In November 2004, we entered into a new $750 million, five-year senior credit facility, which contains a sub-facility for Canadian borrowings up to $300 million. The new facility extends our maturities, lowers our cost of credit and provides an additional $125 million of liquidity over our previous facility. The facility can be expanded to $1 billion.

        We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, credit facility borrowings, the issuance of senior unsecured notes and the sale of additional common units.

        We expect to spend approximately $128.1$139.4 million on expansion capital projects during 2004. This includes our original estimate of expansion capital, newly announced projects and expansion capital associated with the Link acquisition. Our 2004 expansion capital projects include the following notable projects with the estimated cost for the entire year (in millions).year.

Project

  

 Incurred through
September 30, 2004

 Estimated to
be incurred in the
fourth quarter of 2004

 2004
Total


 (in millions)

Cushing to Caney pipeline project $33.6 $14.6 $27.4 $42.0
Trenton pipeline expansion 0.7 18.6 19.3
Capital projects and upgrades associated with the Link acquisition 4.8 4.2 9.0
Capital projects and upgrades associated with the CalVen acquisition  6.0 6.0
Cushing Phase IV expansion 10.0 10.0  10.0
Capital projects and upgrades associated with the Link acquisition 19.1
Upgrade and expansion related to acquisitions made in 2003 24.8 8.2 0.9 9.1
Capital projects and upgrades associated with the CalVen acquisition 7.1
Iatan System expansion 6.6 3.7  3.7
Other 26.9 25.6 14.7 40.3
 
 
 
 
 $128.1 $67.6 $71.8 $139.4
 
 
 
 

        In addition, we expect to spend approximately $14.1$10.1 million on maintenance capital projects during 2004. For the first halfnine months of 2004, we have incurred approximately $32.0 million related to expansion capital projects and approximately $3.1$6.1 million on maintenance capital projects.

        We will also have additional cash funding requirements related to the Link acquisition. The aggregate estimated purchase price for the Link acquisition is approximately $326.1 million, of which approximately $268.0 million (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) was funded at closing. The approximately $58.0 million balance includes acquisition related costs and net liabilities assumed.



        We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity.

 
 Six Months
Ended
June 30,

 
 
 2004
 2003
 
 
 (in millions)

 
Cash provided by (used in):       
 Operating activities $147.1 $204.8 
 Investing activities  (474.6) (139.8)
 Financing activities  334.0  (63.0)
 
 Nine Months Ended
September 30,

 
 
 2004
 2003
 
 
 (in millions)

 
Cash provided by (used in):       
 Operating activities $113.1 $236.1 
 Investing activities  (567.3) (185.2)
 Financing activities  453.4  (51.0)

        Operating Activities.    The primary drivers of our cash flow from operations are (i) the collection of amounts related to the sale of crude oil and LPG and the transportation of crude oil for a fee and (ii) the payment of amounts related to the purchase of crude oil and LPG and other expenses, principally field operating costs, general and administrative expenses and interest expense. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except in the months that we store inventory because of contango market conditions or in months that we increase linefill. The storage of crude oil in periods of a contango market can have a material impact on our cash flows from operating activities for the period we pay for and store the crude oil and the subsequent period that we receive proceeds from the sale of the crude oil. When we store crude oil, we borrow on our credit facilities to pay for the crude oil and the impact on operating cash flow is negative. Conversely, cash flow from operations increases in the period we collect the cash from the sale of the stored crude oil. To a lesser extent, our cash flow from operating activities is also impacted by the level of LPG inventory stored at period end. Cash flow from operations was $147.1$113.1 million and $204.8$236.1 million in 2004 and 2003, respectively.

        Investing Activities.    Net cash used in investing activities in 2004 and 2003 consisted predominantly of cash paid for acquisitions. Net cash used in 2004 was $474.6$567.3 million and was primarily comprised of (i) $142.3$142.5 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003) (ii) approximately $280$283 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition and (iv) $32.2approximately $46.2 million paid for the Schaefferstown acquisition (including inventory of $14.2 million) (v) approximately $63.6 million paid for additions to property and equipment. Includedequipment, and (vi) approximately $10.2 million paid for linefill on assets that we own. Some of the major items included in cash paid for additions to property and equipment is (i) approximately $6.6$8.6 million related to the Cushing Phase IV expansion, (ii) approximately $5.0 million related to the Iatan System expansion, (iii) approximately $3.0$5.4 million of maintenance capital, (iv) and approximately $1.2$10.7 million related to the Cushing to Caney pipeline project.project, and (v) approximately $6.6 million related to our Red River pipeline system. Net cash used in investing activities in 2003 includes approximately $79.6$99.9 million paid for acquisitions and approximately $37.5$52.2 million for additions to property and equipment. In addition, approximately $28.5$40.4 million was paid for linefill on assets that we own. We received proceeds from sales of assets of approximately $7.1 million.

        Financing Activities.    Cash provided by financing activities in 2004 was approximately $334.0$453.4 million and was comprised of (i) approximately $100.9$100.8 million of proceeds from the issuance of Class C common units, (ii) approximately $160.9 million of proceeds from the issuance of common units, (iii) approximately $346.4 million of proceeds from the sale of senior notes, (iv) net short and long-term borrowings under our revolving credit facility of approximately $403.7$4.7 million, used primarily to fund the purchase price of the Capline and Link acquisitions, (iii)(v) net repayments under our short-term letter of credit and hedged inventory facility of approximately $96.1$42.2 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions and (iv) $72.7(vi) $114.5 million of distributions



paid to common unitholders and the general partner. Cash used in financing activities in 2003 consisted of (i) approximately $63.9$161.9 million of proceeds from the issuance of common units used to pay down outstanding balances on the revolving credit facility and a secured term loan, (ii) $58.8$89.3 million of distributions paid to unitholders and the general partner, (iii) a $7.0$43.0 million repayment of a maturity underprincipal repayments of our senior secured term loan,loans, (iv) net long-term borrowingsrepayments under our revolving credit facilities of $29.1$13.1 million, and (v) net short-term debt repayments of $90.2$67.3 million primarily from the proceeds of inventory sales.

        Export License Matter.    In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS"


"BIS") of the U.S. Department of Commerce. In 2002, we determined that we may have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, weWe have received a request from the BIS for additional information.information, which we are in the process of providing. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of this matter.

        Litigation.    We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

        Other.    A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The trend appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities.


        The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

        We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business.

Commitments

        Contractual Obligations.    In the ordinary course of doing business we enter into various contractual obligations for varying terms and amounts. The following table includes our non-cancelable contractual


obligations as of September 30, 2004, and our best estimate of the period in which the obligation will be settled:

 
 2004
 2005
 2006
 2007
 2008
 Thereafter
 Total
 
 (in millions)

Long-term debt $ $ $0.4 $30.0 $ $810.0 $840.4
Operating leases(1)  4.1  15.9  13.9  10.3  5.7  13.1  63.0
Capital expenditure obligations  46.0  8.7          54.7
Other long-term liabilities  0.8  0.5  0.2        1.5
  
 
 
 
 
 
 
 Total $50.9 $25.1 $14.5 $40.3 $5.7 $823.1 $959.6
  
 
 
 
 
 
 

(1)
Operating leases are primarily for office rent and trucks used in our gathering activities.

        In addition to the items in the table above, we have entered into various operational commitments and agreements related to pipeline operations and to the marketing, transportation, terminalling and storage of crude oil and the marketing and storage of LPG. The majority of these contractual commitments are for the purchase of crude oil and LPG that are made under contracts that range in term from a thirty-day evergreen to three years. A substantial portion of the contracts that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice. From time to time, we also enter into various types of sale and exchange transactions including fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The volume and prices of these purchase and sale contracts are subject to market volatility and fluctuate with changes in the NYMEX price of crude oil from period to period. During the third quarter 2004, these purchases averaged approximately $1.8 billion per month.

        Letters of Credit.    In connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to seventy-day periods and are terminated upon completion of each transaction. At September 30, 2004, we had outstanding letters of credit under our various facilities of approximately $123.9 million.

Recent Accounting Pronouncements

        In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. Although the adoption of EITF 03-06 did not result in a change in the Partnership's earnings per limited partner unit for any of the periods presented, the adoption may have an impact on earnings per limited partner unit in future periods if net income exceeds distributions. The effect of applying EITF 03-06 on prior periods was not material except for the year ended December 31, 2000, which has been restated as shown below.

 
 2000
Prior to the adoption of SFAS 145(1) or EITF 03-06 $2.64

After the adoption of SFAS 145 but prior to the adoption of EITF 03-06

 

$

2.20

After the adoption of both SFAS 145 and EITF 03-06

 

$

2.13

(1)
SFAS 145 "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections".

Forward-Looking Statements and Associated Risks

        All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate,



"estimate," "expect," "plan," "intend" and "forecast," and similar expressions and statements regarding our business strategy, plans and objectives for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

the success of our risk management activities;

        Other factors, such as the "Risk Factors Related to ourOur Business" and the Recent Disruption in Industry Credit Markets discussed in Item 7 of our most recent annual report on Form 10-K/A Amendment No. 1, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.


Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

        The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in Item 7A in our 2003 Form 10-K/A Amendment No. 1. There have not been any material changes in that information other than those discussed below.



        AsAll of Juneour open commodity price risk derivatives at September 30, 2004 were categorized as non-trading. The fair value of these instruments and December 31,the change in fair value that would be expected from a 10 percent price decrease are shown in the table below:

 
 Fair
Value

 Effect of 10%
Price Decrease

 
 
 (in millions)

 
Crude oil:       
Futures contracts $29.2 $(15.5)
Swaps and options contracts $(16.0)$(1.2)
LPG:       
Futures contracts $ $ 
Swaps and options contracts $(2.6)$3.6 

        We utilize both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we utilize interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for variable rate debt outstanding at September 30, 2004. The 7.75% senior notes issued during 2002, the 5.625% senior notes issued during 2003, the 4.75% senior notes issued during 2004, and the 5.88% senior notes issued during 2004 are fixed rate notes and their interest rates are not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance plus the applicable margin. The average interest rates presented below are based upon rates in effect at September 30, 2004. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates.

 
 Expected Year of Maturity
 
 
 2004
 2005
 2006
 2007
 2008
 Thereafter
 Total
 
 
 (in millions)

 
Liabilities:                      
 Short-term debt—variable rate $122.9 $ $ $ $ $ $122.9 
  Average interest rate  2.7%           2.7%
 Long-term debt—variable rate $ $ $0.4 $30.0 $ $10.0 $40.4 
  Average interest rate      6.5% 4.7%   2.8% 4.3%

        At September 30, 2004, we had forward exchange contracts that allow us to exchange Canadian dollars for U.S. dollars, quarterly, at set exchange rates as detailed below:

 
 Canadian
Dollars

 US
Dollars

 Rate
 
 ($ in millions)

  
2004 $5.0 $3.8 1.32 to 1
2005 $3.0 $2.3 1.33 to 1
2006 $2.0 $1.5 1.32 to 1

        At September 30, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $21.0 million effectively converting this amount of our U.S. dollar denominated debt to $32.5 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate



of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. in May 2005 and has a final maturity in May 2006 ($19.0 million U.S.).

        We estimate the fair value of these instruments based on current termination values. The table shown below summarizes the fair value of our crude oil futures contracts was approximately $18.6 million and $7.5 million respectively. A 10% price decrease would result in a decrease in fair valueforeign currency hedges by year of $1.4 million and $6.4 million at June 30, 2004 and December 31, 2003, respectively.maturity:


 
 Year of Maturity
 
 
 2004
 2005
 2006
 2007
 Total
 
 
 (in millions)

 
Forward exchange contracts $(0.1)$(0.4)$(0.2)$ $(0.7)
Cross currency swaps  (0.1) (0.8) (4.1)   (5.0)
  
 
 
 
 
 
Total $(0.2)$(1.2)$(4.3)$ $(5.7)
  
 
 
 
 
 


Item 4. CONTROLS AND PROCEDURES

        We maintain "disclosure controls and procedures," which we refer to as our "DCP." The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for timely disclosure of such information in accordance with the securities laws and SEC regulations and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

        Applicable SEC rules require our management to evaluate, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our DCP as of JuneSeptember 30, 2004. Management (including our Chief Executive Officer and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP as of JuneSeptember 30, 2004, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

        In addition to the information concerning our DCP, we are required to disclose any change in our internal control over financial reporting ("internal control") that occurred during the secondthird quarter and that has materially affected, or is reasonably likely to materially affect, our internal control. There were none. However, in the process of documenting and testing our internal control in connection with future compliance with Rule 13a-15(c) under the Exchange Act of 1934, as amended (required by Section 404 of the Sarbanes/OxleySarbanes-Oxley Act of 2002) we have made changes, and will to continue to make changes, to refine and improve our internal control.

        The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350 are furnished with this report as exhibits 32.1 and 32.2.



PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

        Export License Matter.    In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, weWe have received a request from the BIS for additional information.information, which we are in the process of providing. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of this matter.

        Alfons Sperber v. Plains Resources Inc., et. al.    On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unit holders,unitholders, asserts breach of fiduciary duty and breach of contract claims against the



Partnership, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. Attorneys for the parties have executed a memorandum of understanding with respect to a potential settlement of this lawsuit. The settlement, which isThis lawsuit has been settled in principle, subject to finalthe preparation and execution of appropriate settlement documentation and other customary conditions (including a full release with prejudice of the settled claims and approval by the court), would include the payment by defendants of plaintiffs' attorney fees and costs. We consider our cost to settle this matter to be immaterial.court approval.

        We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.


Item 2. CHANGES INUNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

        Securities Not Registered Under the Securities Act.    In connection with the acquisition discussed in Note 2, on April 15, 2004 we issued 3,245,700 Class C common units for $30.81 per unit in a private placement to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors. Affiliates of both Kayne Anderson Capital Advisors and Vulcan Capital own interests in our general partner. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million and were used to reduce the balance outstanding under our revolving credit facilities. The Class C common units are unlisted securities that arepari passu in voting and distribution rights with the Partnership's publicly traded common units. The Class C common units are similar in manymost respects to the Partnership's Class B common units. The Class C units areBoth classes become convertible into common units upon approval by the holders of a majority of the common units (see Note 7 to the Consolidated Financial Statements). Each of the Class B common and Class C common unitholders may request that the Partnership call a meeting of its common unitholders to consider approval of a change in the terms of the Class B units or Class C units, as applicable, to provide that those units may


be converted at the option of the holder into common units. Beginning six months from the closing of the private placement, the Class C unitholders may request that the Partnership call a meeting of its common unitholders to consider approval of the conversion of the Class C units into common units. If the approval of the conversion is not obtained within 120 days of the request, the Class C 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. If the approval of the conversion is not secured within 90 days after the end of the 120-day period, the distribution right increases to 115%.

        Issuer Purchases of Equity Securities.    During June 2004, we purchased 6,250 common units on the open market at an average price of $32.36 per unit (including applicable trade commissions). The purchased units were used to satisfy obligations under our LTIP and are not part of a publicly announced repurchase plan or program.


Item 3. DEFAULTS UPON SENIOR SECURITIES

        None


Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        None


Item 5. OTHER INFORMATION

        Communications with Directors.    Our security holders and other interested parties may communicate with one or more of our directors (including any committee or the non-management directors as a group) by mail in care of either Tim Moore, General Counsel and Secretary or Sharon Spurlin, Director of Internal Audit, Plains All American Pipeline, L.P., 333 Clay Street, Suite 1600,


Houston, Texas, 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.


Item 6. EXHIBITS AND REPORTS ON FORM 8-K


*3.1 Amendment No. 1,†10.1Credit Agreement dated as of April 15, 2004 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of June 27, 2001

*3.2


Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004

*3.3


Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004

3.4


Second Amendment dated as of July 23, 2004 to Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (Incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed July 27, 2004)

*4.1


Registration Rights Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation, and Vulcan Energy II Inc., dated April 15, 2004

*4.2


Class C Common Unit Purchase Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation, and Vulcan Energy II Inc., dated March 31, 2004

*10.1


Interim 364-Day Credit Facility dated April 1,November 2, 2004 among Plains All American Pipeline, L.P. (as US Borrower), PMC (Nova Scotia) Company and Plains Marketing Canada, L.P. (as Canadian Borrowers), and Bank One,of America, N.A. and certain other lenders

10.2
 

Supplements to Uncommitted Senior Secured Discretionary Credit Agreement dated July 24, 2004 among Plains Marketing, L.P. and the lenders named therein (incorporated by reference to Exhibit 10.26 to Registration Statement on Form S-1, File No. 333-119738).
10.3Amended and Restated Marketing Agreement, dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the period ended June 30, 2004).

†10.3

 

10.4
Amended and Restated Omnibus Agreement, dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P., and Plains All American GP LLC.LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended June 30, 2004).

†10.4

 

Second Amendment dated as of April 20, 2004 to Credit Agreement dated as of November 21, 2003, as amended.

18.1


Letter re: change in accounting principle

31.1

 

Certification of Principal Executive Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)

31.2
 

Certification of Principal Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)

*32.1
 

Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
  


*32.2

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350

*
Incorporated by reference to the Partnership's Quarterly Report on Form 10-Q for the period ended March 31, 2004.

Filed herewith.

B.*
Reports on Form 8-K.Furnished herewith.

        A Current Report on Form 8-K was furnished on August 4, 2004 in connection with second quarter 2004 results and third and fourth quarter 2004 guidance.

        A Current Report on Form 8-K was filed on July 27, 2004, with an amendment to the Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated as of June 8, 2001, as amended, attached as an exhibit.

        A Current Report on Form 8-K was filed on July 23, 2004, with an underwriting agreement for an equity offering attached as an exhibit.

        A Current Report on Form 8-K was filed on July 21, 2004, in connection with a change in accounting principle.

        A Current Report on Form 8-K was filed on June 29, 2004, with an unaudited balance sheet of Plains AAP, L.P., as of March 31, 2004, attached as an exhibit.

        A Current Report on Form 8-K was filed on June 16, 2004, in connection with the acquisition of substantially all of the operations of Link Energy LLC.

        A Current Report on Form 8-K was furnished on June 16, 2004, in connection with disclosure of updated second quarter and second half of 2004 estimates and earnings guidance.

        A Current Report on Form 8-K was furnished on April 28, 2004, in connection with disclosure of second quarter and second half of 2004 estimates and earnings guidance.

        A Current Report on Form 8-K was filed on April 27, 2004, with an audited balance sheet of Plains AAP, L.P., as of December 31, 2003, attached as an exhibit.

        A Current Report on Form 8-K was furnished on April 16, 2004, in connection with disclosure of our presentation to the IPAA Oil & Gas Investment Symposium.

        A Current Report on Form 8-K was filed on April 15, 2004, in connection with disclosure of our acquisition of substantially all of the operations of Link Energy LLC. The related Purchase and Sale Agreement and Plan of Merger were attached as exhibits.

        A Current Report on Form 8-K was filed on April 7, 2004, in connection with disclosure of the investigation by the Texas Attorney General's office of our acquisition of Link Energy.



SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.

  PLAINS ALL AMERICAN PIPELINE, L.P.

 

 

By:


PLAINS AAP, L.P., its general partner

 

 

By:


PLAINS ALL AMERICAN GP LLC,
its general partner

Date: August 6,November 5, 2004

 

By:


/s/  
GREG L. ARMSTRONG
  

Greg L. Armstrong, Chairman of the Board,
Chief Executive Officer and Director of Plains
All American GP LLC
(Principal Executive Officer)

Date: August 6,November 5, 2004

 

By:


/s/  
PHIL KRAMER
  

Phil Kramer, Executive Vice President and
Chief Financial Officer of Plains All American
GP LLC
(Principal Financial Officer)