Table of Contents

 

 

 

UNITED STATES SECURITIES AND EXCHANGE

COMMISSION

Washington, D.C. 20549

 

FORM 10-Q
 

x

 

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

 

 

 

 

 

For the quarterly period ended September 30, 2008

 

 

 

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

 

76-0582150

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

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)

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  x

 

Accelerated filer  o

 

Non-accelerated filer  o

 

Smaller reporting company  o

 

 

 

 

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

 

At November 4, 2008, there were outstanding 122,911,645 Common Units.

 

 

 



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

 

TABLE OF CONTENTS

 

 

 

Page

PART I. FINANCIAL INFORMATION

 

3

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

 

3

Condensed Consolidated Balance Sheets: September 30, 2008 and December 31, 2007

 

3

Condensed Consolidated Statements of Operations: For the three months and nine months ended September 30, 2008 and 2007

 

4

Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2008 and 2007

 

5

Condensed Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2008

 

6

Condensed Consolidated Statements of Comprehensive Income: For the three months and nine months ended September 30, 2008 and 2007

 

6

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2008

 

6

Notes to the Condensed Consolidated Financial Statements

 

7

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

 

29

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

42

Item 4. CONTROLS AND PROCEDURES

 

42

PART II. OTHER INFORMATION

 

42

Item 1. LEGAL PROCEEDINGS

 

42

Item 1A. RISK FACTORS

 

43

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

43

Item 3. DEFAULTS UPON SENIOR SECURITIES

 

43

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

 

43

Item 5. OTHER INFORMATION

 

43

Item 6. EXHIBITS

 

44

SIGNATURES

 

47

 

2



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except units)

 

 

 

September 30,

 

December 31,

 

 

 

2008

 

2007

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

37

 

$

24

 

Trade accounts receivable and other receivables, net

 

2,911

 

2,561

 

Inventory

 

1,391

 

972

 

Other current assets

 

196

 

116

 

Total current assets

 

4,535

 

3,673

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

5,705

 

4,938

 

Accumulated depreciation

 

(644

)

(519

)

 

 

5,061

 

4,419

 

OTHER ASSETS

 

 

 

 

 

Pipeline linefill in owned assets

 

431

 

284

 

Inventory in third-party assets

 

78

 

74

 

Investment in unconsolidated entities

 

254

 

215

 

Goodwill

 

1,242

 

1,072

 

Other, net

 

269

 

169

 

Total assets

 

$

11,870

 

$

9,906

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

3,138

 

$

2,577

 

Short-term debt

 

1,349

 

960

 

Other current liabilities

 

255

 

192

 

Total current liabilities

 

4,742

 

3,729

 

LONG-TERM LIABILITIES

 

 

 

 

 

Long-term debt under credit facilities and other

 

1

 

1

 

Senior notes, net of unamortized net discount of $6 and $2, respectively

 

3,219

 

2,623

 

Other long-term liabilities and deferred credits

 

257

 

129

 

Total long-term liabilities

 

3,477

 

2,753

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (122,911,645 and 115,981,676 units outstanding, respectively)

 

3,566

 

3,343

 

General partner

 

85

 

81

 

Total partners’ capital

 

3,651

 

3,424

 

Total liabilities and partners’ capital

 

$

11,870

 

$

9,906

 

 

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

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2008

 

2007

 

2008

 

2007

 

 

 

(unaudited)

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

$

8,862

 

$

5,799

 

$

25,118

 

$

13,946

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Crude oil, refined products and LPG purchases and related costs

 

8,369

 

5,455

 

23,929

 

12,884

 

Field operating costs

 

162

 

134

 

458

 

395

 

General and administrative expenses

 

39

 

33

 

130

 

128

 

Depreciation and amortization

 

49

 

43

 

150

 

135

 

Total costs and expenses

 

8,619

 

5,665

 

24,667

 

13,542

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

243

 

134

 

451

 

404

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

4

 

4

 

11

 

12

 

Interest expense (net of capitalized interest of $4, $4, $14 and $10, respectively)

 

(52

)

(39

)

(143

)

(121

)

Interest income and other income (expense), net

 

14

 

2

 

27

 

8

 

Income before tax

 

209

 

101

 

346

 

303

 

 

 

 

 

 

 

 

 

 

 

Current income tax expense

 

(3

)

 

(9

)

(1

)

Deferred income tax benefit (expense)

 

 

(3

)

2

 

(14

)

NET INCOME

 

$

206

 

$

98

 

$

339

 

$

288

 

 

 

 

 

 

 

 

 

 

 

NET INCOME-LIMITED PARTNERS

 

$

173

 

$

77

 

$

256

 

$

231

 

 

 

 

 

 

 

 

 

 

 

NET INCOME-GENERAL PARTNER

 

$

33

 

$

21

 

$

83

 

$

57

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

1.15

 

$

0.66

 

$

2.14

 

$

2.06

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

1.14

 

$

0.66

 

$

2.12

 

$

2.05

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

123

 

116

 

120

 

112

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

124

 

117

 

121

 

113

 

 

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

 

4



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Nine Months Ended
September 30,

 

 

 

2008

 

2007

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

339

 

$

288

 

Adjustments to reconcile to cash flows from operating activities:

 

 

 

 

 

Depreciation and amortization

 

150

 

135

 

SFAS 133 mark-to-market adjustment

 

(72

)

15

 

Inventory valuation adjustment

 

65

 

 

Equity compensation expense

 

27

 

41

 

Deferred income tax (benefit) expense

 

(2

)

14

 

Gain on sale of investment assets

 

(12

)

 

Gain on foreign currency revaluation

 

(2

)

(3

)

Equity earnings in unconsolidated entities, net of distributions

 

(4

)

(11

)

Other

 

(7

)

(2

)

Changes in assets and liabilities, net of acquisitions:

 

 

 

 

 

Trade accounts receivable and other

 

(338

)

(288

)

Inventory

 

(521

)

410

 

Accounts payable and other current liabilities

 

619

 

368

 

Due to related parties

 

(3

)

2

 

 

 

 

 

 

 

Net cash provided by operating activities

 

239

 

969

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions (Note 4)

 

(662

)

(69

)

Additions to property, equipment and other

 

(446

)

(402

)

Investment in unconsolidated entities

 

(35

)

(9

)

Cash paid for linefill in assets owned

 

(8

)

(18

)

Proceeds from sales of assets

 

36

 

14

 

 

 

 

 

 

 

Net cash used in investing activities

 

(1,115

)

(484

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net borrowings/(repayments) on revolving credit facility

 

259

 

(126

)

Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility

 

111

 

(417

)

Proceeds from the issuance of senior notes (Note 6)

 

597

 

 

Net proceeds from the issuance of common units (Note 8)

 

315

 

383

 

Distributions paid to common unitholders (Note 8)

 

(308

)

(272

)

Distributions paid to general partner (Note 8)

 

(84

)

(58

)

Other financing activities

 

(4

)

(1

)

 

 

 

 

 

 

Net cash provided by (used in) financing activities

 

886

 

(491

)

 

 

 

 

 

 

Effect of translation adjustment on cash

 

3

 

8

 

Net increase (decrease) in cash and cash equivalents

 

13

 

2

 

Cash and cash equivalents, beginning of period

 

24

 

11

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

37

 

$

13

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

143

 

$

146

 

 

 

 

 

 

 

Cash paid for income taxes

 

$

8

 

$

3

 

 

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

 

5



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

 

 

 

 

 

 

 

General

 

Partners’

 

 

 

Common Units

 

Partner

 

Capital

 

 

 

Units

 

Amount

 

Amount

 

Amount

 

 

 

(unaudited)

 

Balance at December 31, 2007

 

116

 

$

3,343

 

$

81

 

$

3,424

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

256

 

83

 

339

 

 

 

 

 

 

 

 

 

 

 

Issuance of common units

 

7

 

309

 

6

 

315

 

 

 

 

 

 

 

 

 

 

 

Issuance of common units under Long Term Incentive Plans (“LTIP”)

 

 

1

 

 

1

 

 

 

 

 

 

 

 

 

 

 

Distributions

 

 

(308

)

(84

)

(392

)

 

 

 

 

 

 

 

 

 

 

Class B Units of Plains AAP, L.P.

 

 

14

 

 

14

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive loss

 

 

(49

)

(1

)

(50

)

 

 

 

 

 

 

 

 

 

 

Balance at September 30, 2008

 

123

 

$

3,566

 

$

85

 

$

3,651

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2008

 

2007

 

2008

 

2007

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

206

 

$

98

 

$

339

 

$

288

 

Other comprehensive income/(loss)

 

(4

)

43

 

(50

)

88

 

Comprehensive income

 

$

202

 

$

141

 

$

289

 

$

376

 

 

CONDENSED CONSOLIDATED STATEMENT OF
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

 

 

Derivative

 

Translation

 

 

 

 

 

Instruments

 

Adjustments

 

Total

 

 

 

(unaudited)

 

Balance at December 31, 2007

 

$

4

 

$

176

 

$

180

 

 

 

 

 

 

 

 

 

Reclassification adjustments for settled contracts

 

12

 

 

12

 

Changes in fair value of outstanding hedge positions

 

35

 

 

35

 

Currency translation adjustment

 

 

(97

)

(97

)

Total period activity

 

47

 

(97

)

(50

)

Balance at September 30, 2008

 

$

51

 

$

79

 

$

130

 

 

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

 

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Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

(unaudited)

 

Note 1—Organization and Basis of Presentation

 

As used in this Form 10-Q, the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise. References to our “general partner,” as the context requires, include any or all of PAA GP LLC, Plains AAP, L.P. and Plains All American GP LLC.

 

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2007 Annual Report on Form 10-K. 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.  The results of operations for the three months and nine months ended September 30, 2008 should not be taken as indicative of the results to be expected for the full year.

 

Note 2—Recent Accounting Pronouncements

 

In June 2008, the Emerging Issues Task Force (“EITF”) issued Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“EITF 03-6-1”).  EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per unit (“EPU”) under the two-class method.  EITF 03-6-1 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years.  All prior-period EPU data presented will be adjusted retrospectively to conform with the provisions of EITF 03-6-1. We will adopt EITF 03-6-1 on January 1, 2009. Adoption will not impact our distributions to limited partners, financial position, results of operations or cash flows.

 

In April 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. FAS 142-3 “Determination of the Useful Life of Intangible Assets” (“FSP No. FAS 142-3”).  FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under Statement of Financial Accounting Standard (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”).  The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other generally accepted accounting principles.  This FSP will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  We will adopt the FSP on January 1, 2009. Adoption will not impact our financial position, results of operations or cash flows.

 

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No. 133” (“SFAS 161”).  SFAS 161 requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”) and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  SFAS 161 will be effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.  We will adopt SFAS 161 on January 1, 2009.  Adoption will not impact our financial position, results of operations or cash flows.

 

In March 2008, the EITF issued Issue No. 07-04, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-04”).  EITF 07-04 addresses the application of the two-class method under SFAS No. 128 in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. The two-class method is an earnings allocation formula that determines EPU for each class of common units and participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. EITF 07-04 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt EITF 07-04 on January 1, 2009. Adoption will impact the net income available to limited partners used in our computation of EPU but will not impact our distributions to limited partners, financial position, results of operations or cash flows.

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).  SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements.  The provisions of SFAS 157 were deferred for one year for certain non-financial assets and non-financial liabilities, including asset retirement obligations, goodwill, intangible assets and long-lived assets.  We adopted SFAS 157 as of January 1, 2008 with the exception of those assets and liabilities that are subject to the deferral. The provisions of SFAS 157 are to be applied prospectively and require new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value.  See Note 10 to our Condensed Consolidated Financial Statements for additional disclosure.

 

Note 3—Trade Accounts Receivable

 

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of refined products and LPG. These purchasers include refineries, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our marketing activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

 

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The U.S. and world financial markets are extremely volatile, the economy has weakened, and many well-known and previously sound financial institutions are experiencing significant difficulties. In addition, during the first half of 2008 the values of crude oil and refined products reached historically high levels, but recently energy prices have dropped to levels seen last year. This volatility in the financial markets combined with the significant energy price volatility have caused liquidity issues impacting many companies, which in turn have increased the potential credit risks associated with certain counterparties with which we do business. Recently, we have seen significant actions taken by the U.S. government in an attempt to provide liquidity and stability to financial institutions and the financial markets.

 

We have a rigorous credit review process and closely monitor these conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, advance cash payments or “parental” guarantees.

 

At September 30, 2008 and December 31, 2007, we had approximately $73 million and $43 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with most of our counterparties. These arrangements cover a significant portion of our transactions and also serve to mitigate credit risk.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.  At September 30, 2008 and December 31, 2007, substantially all of our net accounts receivable classified as current assets were less than 60 days past their scheduled invoice date.  Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts may vary significantly from estimated amounts.

 

Note 4—Acquisitions and Investment in Unconsolidated Entities

 

Acquisitions

 

In May 2008, we completed the acquisition of Rainbow Pipe Line Company, Ltd. (“Rainbow”) for approximately $688 million.  The assets acquired include approximately (i) 480 miles of mainline crude oil pipelines, (ii) 140 miles of gathering pipelines, (iii) 570,000 barrels of tankage along the system and (iv) 1 million barrels of crude oil linefill. The system currently has a throughput capacity of approximately 200,000 barrels per day and 2007 volumes on the system averaged approximately 195,000 barrels per day.  The acquired operations are reflected primarily in our transportation segment.

 

In anticipation of closing the Rainbow acquisition, we entered into forward currency exchange contracts, which exchanged Canadian dollars and US dollars, to hedge the foreign currency exchange risk inherent in the acquisition price. Additionally, we entered into a financial option strategy, whereby we established a minimum and maximum per barrel price to hedge the commodity price risk associated with the anticipated purchase of crude oil linefill.  We recognized a gain on those positions of approximately $8 million and $3 million, respectively, which is reflected in our consolidated results of operations in the “Interest income and other income (expense), net” line.

 

The purchase price consisted of the following (in millions):

 

Cash payment to sellers

 

$

660

 

Assumption of Rainbow debt (at estimated fair value)

 

26

 

Estimated transaction costs

 

2

 

 

 

 

 

Total purchase price

 

$

688

 

 

The purchase price allocation related to the Rainbow acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.  The preliminary purchase price allocation is as follows (in millions):

 

Property, plant and equipment

 

$

425

 

Pipeline linefill in owned assets

 

143

 

Intangible assets

 

52

 

Goodwill

 

185

 

Future income tax liability

 

(102

)

Assumption of working capital and other long-term assets and liabilities, including cash (1)

 

(15

)

 

 

 

 

Total

 

$

688

 

 

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(1)  Includes approximately $16 million associated with estimated environmental liabilities.

 

Investment in Unconsolidated Entities

 

During the three months ended September 30, 2008, no contribution was made to PAA/Vulcan Gas Storage, LLC; however, for the nine months ended September 30, 2008, we contributed $35 million.  These contributions did not result in an increase in our ownership interest.  During the three months and nine months ended September 30, 2008, we received distributions of $1 million and $7 million, respectively, from our unconsolidated entities.

 

Note 5—Inventory and Linefill

 

Inventory and linefill consisted of the following (barrels in thousands and dollars in millions, except dollars per barrel amounts):

 

 

 

September 30, 2008

 

December 31, 2007

 

 

 

 

 

 

 

Dollars/

 

 

 

 

 

Dollars/

 

 

 

Barrels

 

Dollars

 

Barrel (1)

 

Barrels

 

Dollars

 

Barrel (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

6,690

 

$

697

 

$

104.19

 

7,365

 

$

592

 

$

80.38

 

LPG

 

10,145

 

678

 

$

66.83

 

6,480

 

363

 

$

56.02

 

Refined products

 

93

 

10

 

$

107.53

 

133

 

11

 

$

82.71

 

Parts and supplies

 

N/A

 

6

 

N/A

 

N/A

 

6

 

N/A

 

Inventory subtotal

 

16,928

 

1,391

 

 

 

13,978

 

972

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Inventory in third-party assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

850

 

62

 

$

72.94

 

986

 

64

 

$

64.91

 

LPG

 

253

 

16

 

$

63.24

 

175

 

10

 

$

57.14

 

Inventory in third-party assets subtotal

 

1,103

 

78

 

 

 

1,161

 

74

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline linefill in owned assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

8,905

 

429

 

$

48.18

 

7,734

 

282

 

$

36.46

 

LPG

 

49

 

2

 

$

40.82

 

43

 

2

 

$

46.51

 

Pipeline linefill in owned assets subtotal

 

8,954

 

431

 

 

 

7,777

 

284

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

26,985

 

$

1,900

 

 

 

22,916

 

$

1,330

 

 

 

 


(1)        The prices listed represent a weighted average associated with various grades and qualities of crude oil, LPG and refined products and, accordingly, are not comparable metrics with published benchmarks for such products.

 

The inventory balances at September 30, 2008 include an inventory valuation adjustment, which resulted in a loss of approximately $65 million, related to certain crude oil and LPG inventories that were revalued to market prices as of September 30, 2008.

 

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Note 6—Debt

 

Debt as of September 30, 2008 and December 31, 2007 consisted of the following (in millions):

 

 

 

September 30,

 

December 31,

 

 

 

2008

 

2007

 

Short-term debt:

 

 

 

 

 

Senior secured hedged inventory facility bearing interest at a rate of 4.1% and 5.3% at September 30, 2008 and December 31, 2007, respectively

 

$

586

 

$

476

 

 

 

 

 

 

 

Working capital borrowings, bearing interest at a rate of 4.0% and 5.5% at September 30, 2008 and December 31, 2007, respectively (1)

 

762

 

482

 

 

 

 

 

 

 

Other

 

1

 

2

 

 

 

 

 

 

 

Total short-term debt

 

1,349

 

960

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

 

 

 

 

 

 

Senior notes, net of unamortized net premium and discount

 

3,219

 

2,623

 

 

 

 

 

 

 

Long-term debt under credit facilities and other (1)

 

1

 

1

 

 

 

 

 

 

 

Total long-term debt (1)

 

3,220

 

2,624

 

 

 

 

 

 

 

Total debt

 

$

4,569

 

$

3,584

 

 


(1)       At September 30, 2008 and December 31, 2007, we have classified $762 million and $482 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”) margin deposits.  NYMEX is part of CME Group Inc.

 

In April 2008, we completed the issuance of $600 million of 6.5% Senior Notes due May 1, 2018. The senior notes were sold at 99.424% of face value. Interest payments are due on May 1 and November 1 of each year, beginning on November 1, 2008. We used the net proceeds from the offering to repay amounts outstanding under our credit facilities.

 

In connection with the sale of the $600 million senior notes, we entered into an exchange and registration rights agreement pursuant to which we agreed to use our reasonable best efforts to, among other things:

 

·                  file, within 180 days after issuance of the senior notes, a registration statement with the SEC relating to an exchange offer for the senior notes;

·                  cause the registration statement to become effective within 270 days after the issuance of the senior notes; and

·                  consummate the exchange offer within 300 days after the issuance of the senior notes.

 

If we fail to meet our obligations under this agreement in a timely manner (a “registration default”), the per annum interest rate on the senior notes will increase for the period from the occurrence of the registration default until such time as the registration default is no longer in effect.  In the event of a registration default, interest on the senior notes will increase by 0.25% during the first 90-day period following the occurrence and during the continuation of a registration default and by an additional 0.25% subsequent to the first 90-day period during which the registration default continues, up to a maximum of 0.50%.  A registration statement relating to the exchange offer for the senior notes was filed and declared effective in September 2008.  The exchange offer is scheduled to expire and close in November 2008.

 

In August 2009, our $175 million 4.75% senior notes will mature. However, since we have the ability and intent to refinance those notes, they are classified as long-term debt within our balance sheet.

 

Credit Facility

 

At September 30, 2008, we had approximately $0.6 billion of availability under our $1.2 billion uncommitted hedged inventory facility, which was set to mature in November 2008. This facility is an uncommitted working capital facility, which is used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility are collateralized by the inventory purchased under the facility and the associated accounts receivable, and will be repaid with the proceeds from the sale of such inventory.  Our utilization under this facility over the last 15 months has averaged approximately $456 million per month.

 

In light of the current uncertainty in the financial markets, recognition of the recent reduction in oil prices and actions we have taken to reduce our potential working capital requirements, on November 6, we replaced this uncommitted facility with a $525 million committed hedged inventory facility.  The new facility’s committed amount may be increased to $1.2 billion, subject to obtaining additional commitments from lenders. Initial proceeds from the new committed facility were used to re-finance the outstanding balance of the previous uncommitted facility and subsequent proceeds will be used to finance purchased or stored hedged inventory. Obligations under the new committed facility are secured by the financed inventory and the associated accounts receivable, and will be repaid from the proceeds of the sale of the financed inventory. The new facility will mature on an annual basis beginning in November 2009 and, except for increased pricing, bears similar terms to the previous facility.

 

Letters of Credit

 

In connection with our crude oil marketing activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil.  At September 30, 2008 and December 31, 2007, we had outstanding letters of credit of approximately $73 million and $153 million, respectively.

 

Note 7—Earnings per Limited Partner Unit

 

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2008 and 2007 (amounts in millions, except per unit data):

 

10



Table of Contents

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2008

 

2007

 

2008

 

2007

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

Net income

 

$

206

 

$

98

 

$

339

 

$

288

 

Less: General partner’s incentive distribution paid

 

(30

)

(20

)

(78

)

(52

)

Subtotal

 

176

 

78

 

261

 

236

 

Less: General partner 2% ownership

 

(3

)

(1

)

(5

)

(5

)

Net income available to limited partners

 

173

 

77

 

256

 

231

 

Less: Pro forma EITF 03-06 additional general partner’s distribution

 

(31

)

 

 

 

Net income available for limited partners under EITF 03-06

 

$

142

 

$

77

 

$

256

 

$

231

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

123

 

116

 

120

 

112

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Weighted average LTIP units (1)

 

1

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

124

 

117

 

121

 

113

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

1.15

 

$

0.66

 

$

2.14

 

$

2.06

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

1.14

 

$

0.66

 

$

2.12

 

$

2.05

 

 


(1)       Our LTIP awards (described in Note 9) that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. The dilutive securities are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in SFAS No. 128, “Earnings per Share.

 

Note 8—Partners’ Capital and Distributions

 

Equity Offerings

 

We completed the following equity offerings of our common units during the nine months ended September 30, 2008 and 2007 (in millions, except units and per unit amounts):

 

 

 

 

 

 

 

 

 

General

 

 

 

 

 

 

 

 

 

Gross

 

Proceeds

 

Partner

 

 

 

Net

 

Period

 

Units Issued

 

Unit Price

 

from Sale

 

Contribution

 

Costs (1)

 

Proceeds

 

April 2008

 

6,900,000

 

$

46.31

 

$

320

 

$

6

 

$

(11

)

$

315

 

June 2007

 

6,296,172

 

$

59.56

 

$

375

 

$

8

 

$

 

$

383

 

 


(1) The April 2008 offering of common units was an underwritten transaction that required us to pay a gross spread.  The direct placement of common units in June 2007 did not involve underwriters and thus did not require a gross spread payment.

 

LTIP Vesting

 

In May 2008, we issued 29,969 common units at a price of $46.58, for a fair value of approximately $1 million in connection with the settlement of vested LTIP awards.

 

Distributions

 

The following table details the distribution we declared subsequent to the third quarter of 2008 and 2007 and distributions declared and paid in the nine months ended September 30, 2008 and 2007, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

 

11



Table of Contents

 

 

 

 

 

Distributions Paid

 

Distributions

 

 

 

 

 

Common

 

General Partner

 

 

 

per limited

 

Date Declared

 

Date Paid or To Be Paid

 

Units

 

Incentive

 

2%

 

Total

 

partner unit

 

October 22, 2008

 

November 14, 2008 (1)

 

$

110

 

$

28

 

$

2

 

$

140

 

$

0.8925

 

July 14, 2008

 

August 14, 2008

 

$

109

 

$

30

 

$

2

 

$

141

 

$

0.8875

 

April 17, 2008

 

May 15, 2008

 

$

100

 

$

25

 

$

2

 

$

127

 

$

0.8650

 

January 16, 2008

 

February 14, 2008

 

$

99

 

$

23

 

$

2

 

$

124

 

$

0.8500

 

October 18, 2007

 

November 14, 2007

 

$

98

 

$

21

 

$

2

 

$

121

 

$

0.8400

 

July 19, 2007

 

August 14, 2007

 

$

96

 

$

20

 

$

2

 

$

118

 

$

0.8300

 

April 17, 2007

 

May 15, 2007

 

$

88

 

$

17

 

$

2

 

$

107

 

$

0.8125

 

January 16, 2007

 

February 14, 2007

 

$

88

 

$

15

 

$

2

 

$

105

 

$

0.8000

 

 


(1)  Payable to unitholders of record on November 4, 2008, for the period July 1, 2008 through September 30, 2008.

 

Upon closing of the Pacific and Rainbow acquisitions, our general partner agreed to reduce the amounts due it as incentive distributions. The total reduction in incentive distributions related to these acquisitions is $75 million. Following the distribution in November 2008, the aggregate remaining incentive distribution reductions related to these acquisitions will be approximately $38 million.

 

Note 9—Equity Compensation Plans

 

Long-Term Incentive Plans

 

For discussion of our LTIP awards, see Note 10 to our Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.  At September 30, 2008 we have the following LTIP awards outstanding (units in millions):

 

 

 

Vesting

 

 

 

 

 

 

 

 

 

 

 

LTIP Units

 

Distribution

 

Estimated Unit Vesting Date

 

Outstanding

 

Amount

 

2008

 

2009

 

2010

 

2011

 

2012

 

1.2

(1)

$3.20

 

 

0.6

 

0.6

 

 

 

1.3

(2)

$3.50 -  $4.00

 

 

 

0.1

 

0.8

 

0.4

 

1.3

(3)

$3.50  - $4.00

 

 

 

0.8

 

0.2

 

0.3

 

3.8

(4) (5)

 

 

 

0.6

 

1.5

 

1.0

 

0.7

 

 


(1)       Upon our February 2007 annualized distribution of $3.20, these LTIP awards satisfied all distribution requirements and will vest upon completion of the respective service periods.

 

(2)       These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.00 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained, these awards will be forfeited. For purposes of this disclosure, the awards are presented above assuming the distribution levels are attained and that the awards will vest on the earliest date possible regardless of our current assessment of probability.

 

(3)       These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.00. Fifty percent of these awards will vest in 2012 regardless of whether the performance conditions are attained. The awards are presented above assuming the distribution levels are attained and that the awards will vest on the earliest date possible regardless of our current assessment of probability.

 

(4)       Approximately 2 million of our 3.8 million outstanding LTIP awards also include distribution equivalent rights (“DERs”), of which 1.2 million are currently earned.

 

(5)       LTIP units outstanding do not include Class B units of Plains AAP, L.P. described below.

 

Our LTIP activity is summarized in the following table (in millions, except weighted average grant date fair values per unit):

 

12



Table of Contents

 

 

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

 

 

Grant Date

 

 

 

Units

 

Fair Value per Unit

 

Outstanding at December 31, 2007

 

3.6

 

$

37.73

 

Granted

 

0.4

 

$

33.77

 

Vested

 

(0.1

)

$

32.44

 

Cancelled or forfeited

 

(0.1

)

$

34.92

 

Outstanding at September 30, 2008

 

3.8

 

$

37.50

 

 

Our accrued liability at September 30, 2008 related to all outstanding LTIP awards and DERs is approximately $57 million, which includes an accrual associated with our assessment that an annualized distribution of $3.75 is probable of occurring. We have not deemed a distribution of more than $3.75 to be probable.  At December 31, 2007, the accrued liability was approximately $51 million.

 

Class B Units of Plains AAP, L.P.

 

At September 30, 2008, 154,000 Class B units were outstanding and 46,000 Class B units were reserved for future grants.  The total grant date fair value of the Class B units outstanding at September 30, 2008 was approximately $34 million, of which approximately $3 million and $14 million was recognized as expense during the three months and nine months ended September 30, 2008, respectively. In August 2008, 21,000 Class B units were earned upon the payment of our second quarter distribution of $0.8875 per unit and an additional 17,500 will be earned 180 days after such payment.  Although the entire economic burden of the Class B units, which are equity classified, is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding, the intent of the Class B units is to provide a performance incentive and encourage retention for certain members of our senior management. Therefore, we recognize the grant date fair value of the Class B units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to Partners’ Capital in our Condensed Consolidated Financial Statements.

 

Other Consolidated Information

 

We refer to our LTIP Plans and the Class B units collectively as our “equity compensation plans.” The table below summarizes the expense recognized and the value of vestings (settled both in units and cash) related to our equity compensation plans (in millions):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2008

 

2007

 

2008

 

2007

 

Equity compensation expense

 

$

3

 

$

1

 

$

27

 

$

41

 

LTIP unit settled vestings

 

$

 

$

1

 

$

1

 

$

18

 

LTIP cash settled vestings

 

$

 

$

 

$

2

 

$

16

 

DER cash payments

 

$

1

 

$

1

 

$

3

 

$

3

 

 

Based on the September 30, 2008 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $51 million of additional expense over the life of our outstanding awards under our equity compensation plans related to the remaining unrecognized fair value. This estimate is based on the closing market price of our units of $39.62 at September 30, 2008. Actual amounts may differ materially as a result of a change in market price and/or probability assessment regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

 

 

 

Equity Compensation

 

 

 

Plan Fair Value

 

Year

 

Amortization (1)

 

2008 (2)

 

$

7

 

2009

 

 

23

 

2010

 

 

13

 

2011

 

 

6

 

2012

 

 

2

 

Total

 

$

51

 

 


(1)       Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at September 30, 2008.

 

(2)       Includes equity compensation plan fair value amortization for the remaining three months of 2008.

 

13



Table of Contents

 

Note 10—Derivative Instruments and Hedging Activities

 

The derivative instruments we use consist primarily of futures and options contracts traded on the NYMEX (part of CME Group Inc.), the ICE and over-the-counter (“OTC”), including commodity swap and option contracts entered into with financial institutions and other energy companies.  We use derivatives as an effective element of our risk management strategy and do so to eliminate or mitigate risk inherent in our business.

 

Summary of Financial Impact

 

A summary of the earnings impact of all derivative activities, including the change in fair value of open derivatives and settled derivatives recognized in earnings, is as follows (in millions, losses designated in parentheses):

 

 

 

For the Three Months Ended

 

For the Three Months Ended

 

 

 

September 30, 2008

 

September 30, 2007

 

 

 

Mark-to-
market, net

 

Settled

 

Total

 

Mark-to-
market, net

 

Settled

 

Total

 

Commodity price risk hedging (1)

 

$

164

 

$

(172

)

$

(8

)

$

(14

)

$

38

 

$

24

 

Controlled trading program

 

 

 

 

 

 

 

Interest rate risk hedging

 

 

 

 

2

 

 

2

 

Currency exchange rate risk hedging

 

(1

)

 

(1

)

(1

)

4

 

3

 

Total

 

$

163

 

$

(172

)

$

(9

)

$

(13

)

$

42

 

$

29

 

 

 

 

For the Nine Months Ended

 

For the Nine Months Ended

 

 

 

September 30, 2008

 

September 30, 2007

 

 

 

Mark-to-market, net

 

Settled

 

Total

 

Mark-to-
market, net

 

Settled

 

Total

 

Commodity price risk hedging (1)

 

$

74

 

$

81

 

$

155

 

$

(19

)

$

121

 

$

102

 

Controlled trading program

 

 

 

 

 

1

 

1

 

Interest rate risk hedging

 

 

 

 

2

 

(1

)

1

 

Currency exchange rate risk hedging

 

(2

)

7

 

5

 

3

 

4

 

7

 

Total

 

$

72

 

$

88

 

$

160

 

$

(14

)

$

125

 

$

111

 

 


(1)             Included in Commodity price risk hedging are certain physical commodity contracts that meet the definition of a derivative and are not excluded from SFAS 133 under the normal purchase and normal sale scope exception.

 

The breakdown of the net mark-to-market impact to earnings between derivatives that do not qualify for hedge accounting and the ineffective portion of cash flow hedges is as follows (in millions, losses designated in parentheses):

 

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2008

 

2007

 

2008

 

2007

 

Derivatives that are not designated for hedge accounting (1)

 

$

164

 

$

(14

)

$

72

 

$

(13

)

Ineffective portion of cash flow hedges

 

(1

)

1

 

 

(1

)

Total

 

$

163

 

$

(13

)

$

72

 

$

(14

)

 


(1)             These derivatives that do not qualify for hedge accounting consist of derivatives that are an effective element of our risk management strategy but we did not elect to receive hedge accounting treatment due to various factors including that the positions have historically been immaterial and the required documentation was considered extensive and burdensome. These gains or losses are generally offset by future physical positions that are not included in the mark-to-market calculation because they qualify for the normal purchase and normal sale scope exception under SFAS 133.

 

The following table summarizes the net assets and liabilities on our condensed consolidated balance sheet that are related to the fair value of our open derivative positions (in millions):

 

14



Table of Contents

 

 

 

September 30,

 

December 31,

 

 

 

2008

 

2007

 

Other current assets

 

$

169

 

$

56

 

Other long-term assets

 

84

 

26

 

Other current liabilities

 

(118

)

(97

)

Other long-term liabilities and deferred credits

 

(51

)

(22

)

Other

 

 

1

 

Net asset (liability)

 

$

84

 

$

(36

)

 

The net asset related to the fair value of our open derivative positions consists of unrealized gains/losses recognized in earnings and unrealized gains/losses deferred to Accumulated Other Comprehensive Income (“AOCI”) as follows, by category (in millions, losses designated in parentheses):

 

 

 

September 30, 2008

 

December 31, 2007

 

 

 

Net Asset /

 

 

 

 

 

Net Asset /

 

 

 

 

 

 

 

(Liability)

 

Earnings

 

AOCI

 

(Liability)

 

Earnings

 

AOCI

 

Commodity price risk hedging

 

$

75

 

$

27

 

$

48

 

$

(38

)

$

(48

)

$

10

 

Controlled trading program

 

 

 

 

 

 

 

Interest rate risk hedging (1)

 

2

 

2

 

 

3

 

3

 

 

Currency exchange rate risk hedging

 

7

 

(3

)

10

 

(1

)

 

(1

)

 

 

$

84

 

$

26

 

$

58

 

$

(36

)

$

(45

)

$

9

 

 


(1)  Amounts are presented on a net basis and include both the net asset/(liability) related to our interest rate derivatives and any fair value adjustment related to our underlying debt.

 

In addition to the $58 million and $9 million of unrealized gains deferred to AOCI for open derivative positions as of September 30, 2008 and as of December 31, 2007, respectively, AOCI also includes deferred losses of approximately $7 million and $5 million as of September 30, 2008 and December 31, 2007, respectively. These deferred losses relate to terminated interest rate hedges that were settled in connection with the issuance and refinancing of debt agreements over the past five years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the underlying debt.

 

The total amount of deferred net gain recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the related physical purchase or delivery of the underlying commodity, (ii) interest expense accruals associated with the underlying debt instruments and (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain Canadian dollar (“CAD”) denominated intercompany interest receivables. Of the total net gain deferred in AOCI at September 30, 2008, a net gain of approximately $24 million will be reclassified to earnings in the next twelve months. Of the remaining deferred gain in AOCI, approximately 84% is expected to be reclassified to earnings prior to 2012. Because a portion of these amounts is 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. During the three months and nine months ended September 30, 2008 and 2007, no amounts were reclassified to earnings from AOCI in connection with forecasted transactions that were no longer considered probable of occurring.

 

We do not offset the assets and liabilities associated with the fair value of our derivatives with amounts we have recognized related to our right to receive or our obligation to pay cash collateral. When we deposit cash collateral with our brokers, we recognize a broker receivable, which is a component of our accounts receivable. Based on the outstanding positions held in our broker accounts, our aggregate initial margin requirements with our brokers were approximately $6 million and $33 million as of September 30, 2008 and December 31, 2007, respectively. Changes in the value of our positions in the broker accounts result in increases or decreases in the amount of margin we have to provide to maintain our initial margin requirements (variation margin).  Variation margin was favorable as of September 30, 2008 and December 31, 2007 and reduced the amount of our cash required to maintain our initial margin requirements.

 

Adoption of SFAS 157

 

Effective January 1, 2008, we adopted SFAS 157 which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.  As defined in SFAS 157, fair value is the price that would be received from selling an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. Whenever possible, we use market data that market participants would use when pricing an asset or liability. These inputs can be either readily observable or market corroborated. We apply the market approach for recurring fair value measurements related to our derivatives. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted

 

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prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

 

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

 

 

 

Fair Value as of September 30, 2008 (in millions)

 

Recurring Fair Value Measures

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

170

 

$

4

 

$

67

 

$

241

 

Interest rate derivatives

 

 

 

2

 

2

 

Foreign currency derivatives

 

 

 

10

 

10

 

Total assets at fair value

 

$

170

 

$

4

 

$

79

 

$

253

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

(103

)

$

 

$

(63

)

$

(166

)

Foreign currency derivatives

 

 

 

(3

)

(3

)

Total liabilities at fair value

 

$

(103

)

$

 

$

(66

)

$

(169

)

 

 

 

 

 

 

 

 

 

 

Net asset/(liability) at fair value

 

$

67

 

$

4

 

$

13

 

$

84

 

 

  The determination of the fair values above incorporates various factors required under SFAS 157.  These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities.  The fair value of our level 3 commodity derivatives, interest rate derivatives and foreign currency derivatives includes adjustments for credit risk.  We measure credit risk by deriving a probability of default from market observed credit default swap spreads as of the measurement date.  The probability of default is applied to the net credit exposure of each of our counterparties and includes a recovery rate adjustment.  The recovery rate is an estimate of what would ultimately be recovered through a bankruptcy proceeding in the event of default.  Fair value adjustments related to our credit risk resulted in a gain of $2 million during the three month period ended September 30, 2008.    Fair value adjustments related to counterparty credit risk resulted in a deferred loss of $2 million in AOCI during the three month period ended September 30, 2008.  There were no changes to any of our valuation techniques during the period.

 

Level 1

 

Included within level 1 of the fair value hierarchy are commodity derivatives that are exchange traded.  Exchange-traded derivative contracts include futures and exchange-traded options.  The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets and is therefore classified within level 1 of the fair value hierarchy.

 

Level 2

 

Included within level 2 of the fair value hierarchy is a physical commodity supply contract that meets the definition of a derivative but is not excluded from SFAS 133 under the normal purchase and normal sale scope exception.  The fair value of this commodity derivative is measured with level 1 inputs for similar but not identical instruments and therefore must be included in level 2 of the fair value hierarchy.

 

Level 3

 

Included within level 3 of the fair value hierarchy are (i) commodity derivatives that are not exchange traded, (ii) interest rate derivatives and (iii) foreign currency derivatives, which are described as follows:

 

·                          Commodity Derivatives:  Level 3 commodity derivatives include OTC commodity derivatives such as forwards, swaps and options and certain physical commodity contracts.  The fair value of our level 3 derivatives is based on either an indicative broker or dealer price quotation or a valuation model.  Our valuation models utilize inputs such as price, volatility and correlation and do not involve significant management judgments.

 

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·                          Interest Rate Derivatives:  Level 3 interest rate derivatives include interest rate swaps.  The fair value of our interest rate derivatives is based on indicative broker or dealer price quotations.  Broker or dealer price quotations are corroborated with objective inputs including forward LIBOR curves and forward Treasury yields that are obtained from pricing services.

 

·                          Foreign Currency Derivatives:  Level 3 foreign currency derivatives include foreign currency swaps, forward exchange contracts and options.  The fair value of our foreign currency derivatives is based on indicative broker or dealer price quotations.  Broker or dealer price quotations are corroborated with objective inputs including forward CAD/USD forward exchange rates that are obtained from pricing services.

 

The majority of the derivatives included in level 3 of the fair value hierarchy are classified as level 3 because the broker or dealer price quotations used to measure fair value and the pricing services used to corroborate the quotations are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact.  However, the fair value of these level 3 derivatives is not based upon significant management assumptions or subjective inputs.

 

Rollforward of Level 3 Net Liability

 

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives measured at fair value using inputs classified as level 3 in the fair value hierarchy (in millions):

 

Beginning Balance at July 1, 2008 and January 1, 2008, respectively

 

$

(56

)

$

(21

)

Realized and unrealized gains (losses):

 

 

 

 

 

Included in earnings (1)

 

36

 

(45

)

Included in other comprehensive income

 

7

 

5

 

Purchases, issuances, sales and settlements

 

26

 

74

 

Transfers into or out of level 3 (2)

 

 

 

Ending Balance at September 30, 2008

 

$

13

 

$

13

 

 

 

 

 

 

 

Change in unrealized gains (losses) included in earnings relating to level 3 derivatives still held as of September 30, 2008 (3)

 

$

62

 

$

34

 

 


(1)

 

Gains and losses associated with level 3 commodity derivatives are reported in our condensed consolidated statements of operations as crude oil, refined products and LPG sales or purchases. Gains and losses associated with interest rate derivatives are reported in our condensed consolidated statements of operations as other income (expense). Gains and losses associated with foreign currency derivatives are reported in our condensed consolidated statements of operations as either crude oil, refined products and LPG sales or other income (expense).

 

 

 

(2)

 

Transfers into or out of level 3 represent existing assets or liabilities that were either previously categorized at a higher level for which the inputs to the model became unobservable or that were previously classified as level 3 for which the lowest significant input became observable during the period. There were no transfers into or out of level 3 during the period.

 

 

 

(3)

 

The change in unrealized gains and losses related to our level 3 assets and liabilities still held at the end of the period are either recognized in earnings or deferred in AOCI through the application of hedge accounting. Unrealized gains and losses related to our level 3 derivatives that are still held at September 30, 2008 and recognized in earnings are included in our condensed consolidated statements of operations as crude oil, refined products and LPG sales or purchases for our commodity derivatives, other income (expense) for our interest rate derivatives and crude oil, refined products and LPG sales or other income (expense) for our foreign currency derivatives.

 

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We believe that a proper analysis of our level 3 gains or losses must incorporate the understanding that these items are generally used to hedge our commodity price risk, interest rate risk and foreign currency exchange risk and are therefore offset by the underlying transactions.

 

Note 11—Income Taxes

 

U.S. Federal and State Taxes

 

 As a master limited partnership, we are not subject to U.S. federal income taxes; rather, the tax effect of our operations is passed through to our unitholders. We are subject to state income taxes in some states but the expense is immaterial.

 

Canadian Federal and Provincial Taxes

 

 Certain of our Canadian subsidiaries are corporations for Canadian tax purposes; thus their operations are subject to Canadian federal and provincial income taxes. The remainder of our Canadian operations is conducted through an operating limited partnership, which is a flow-through entity for tax purposes. This entity is subject to Canadian legislation passed in 2007 that imposes entity-level taxes on certain types of flow-through entities. This legislation includes safe harbor guidelines that grandfather certain existing entities (which would include us) and delay the effective date of such legislation until 2011 provided that such entities do not exceed the normal growth guidelines. Although we continuously review acquisition opportunities that, if consummated, could cause us to exceed the normal growth guidelines, we believe that we are currently within the normal growth guidelines.

 

Note 12—Commitments and Contingencies

 

Litigation

 

Pipeline Releases.   In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $4 million to $5 million. In cooperation with the appropriate state and federal environmental authorities, we have completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. The EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice (the “DOJ”) for further investigation in connection with a civil penalty enforcement action under the Federal Clean Water Act. We have cooperated in the investigation and are currently involved in settlement discussions with the DOJ and the EPA. Our assessment is that it is probable we will pay penalties related to the releases. We may also be subjected to injunctive remedies that would impose additional requirements, costs and constraints on our operations. We have accrued our current estimate of the likely penalties as a loss contingency, which is included in the estimated aggregate costs set forth above. We understand that the maximum permissible penalty, if any, that the EPA could assess with respect to the subject releases under relevant statutes would be approximately $6.8 million. Such statutes contemplate the potential for substantial reduction in penalties based on mitigating circumstances and factors. We believe that several of such circumstances and factors exist, and thus have been a primary focus in our discussions with the DOJ and EPA with respect to these matters.

 

On November 15, 2006, we completed the Pacific merger. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.

 

The People of the State of California v. Pacific Pipeline System, LLC (“PPS”).   In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger. The release occurred when the pipeline was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. Total projected

 

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emergency response, remediation and restoration costs are approximately $26 million, substantially all of which have been incurred and recovered under a pre-existing PPS pollution liability insurance policy.

 

In connection with this release, in March 2006, PPS, a subsidiary acquired in the Pacific merger, was served with a four-count misdemeanor criminal action in the Los Angeles Superior Court Case No. 6NW01020, which alleged the violation by PPS of two strict liability statutes under the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, and violations of two sections of the California Water Code for the willful and intentional discharge of pollution into state waters. On October 15, 2008 this criminal action (all four counts) was dismissed with prejudice and PPS was not subjected to any fine or penalty.

 

In September 2008, PPS was served by the State of California with a civil complaint in connection with this release, in the Los Angeles Superior Court Case No. BC398627, alleging violations of the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, violations of two sections of the California Water Code for the unlawful discharge of waste into state waters without a permit, and violations of the Public Nuisance Code alleging that discharge of petroleum into waters of the state had created a public nuisance.  This case was settled in October 2008.  Pursuant to the terms of the settlement agreement, PPS paid no fine or penalty, but made civil settlement payments to various agencies of the State of California in the total amount of approximately $1.1 million.   PPS has submitted these payments to its insurance carrier for reimbursement.

 

United States of America v. Pacific Pipeline Systems, LLC.  In September 2008, the EPA filed a civil complaint against PPS in connection with the March 2005 release described above.  The complaint, which was filed in the Federal District Court for the Central District of California, Civil Action No. CV08-5768DSF(SSX), seeks the maximum permissible penalty under the relevant statutes of approximately $3.7 million. The EPA and DOJ have discretion to reduce the fine, if any, after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the alleged offenses cannot be ascertained. We may also be subjected to injunctive remedies that would impose additional requirements, costs and constraints on our operations. We will defend against these charges. We believe that several defenses and mitigating circumstances and factors exist that could substantially reduce any penalty or fine that might be imposed by the EPA and DOJ, and intend to pursue discussions with the EPA and DOJ regarding such defenses and mitigating circumstances and factors. Although we have established an estimated loss contingency for this matter, we are presently unable to determine whether the March 2005 spill incident may result in a loss in excess of our accrual for this matter. Discussions with the DOJ on behalf of the EPA to resolve this matter have commenced.

 

Exxon v. GATX.   This Pacific legacy matter involves the allocation of responsibility for remediation of MTBE (and other petroleum product) contamination at the Pacific Atlantic Terminals LLC (“PAT”) facility at Paulsboro, New Jersey. The estimated maximum potential remediation cost ranges up to $12 million. Both Exxon and GATX were prior owners of the terminal. We contend that Exxon and GATX are primarily responsible for the majority of the remediation costs. We are in dispute with Kinder Morgan (as successor in interest to GATX) regarding the indemnity by GATX in favor of Pacific in connection with Pacific’s purchase of the facility. In a related matter, the New Jersey Department of Environmental Protection has brought suit against GATX and Exxon to recover natural resources damages. Exxon and GATX have filed third-party demands against PAT, seeking indemnity and contribution. We are vigorously defending against any claim that PAT is directly or indirectly liable for damages or costs associated with the MTBE contamination.

 

Other Pacific-Legacy Matters.   Pacific had completed a number of acquisitions that had not been fully integrated prior to the merger with Plains. Accordingly, we have and may become aware of other matters involving the assets and operations acquired in the Pacific merger as they relate to compliance with environmental and safety regulations, which matters may result in mitigative costs or the imposition of fines and penalties. We are, for instance, in the process of discussing with the Bay Area Air Quality Management District the settlement of certain historical air quality issues at our facilities acquired in the merger.

 

General.   We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

 

Environmental

 

We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified. Although we maintain a program designed to help prevent releases, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our procedures, remove selected assets from service and spend capital to upgrade the assets. The inclusion of additional miles of pipe in our operations may, however, result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with the Pacific merger, which added approximately 5,000 miles of pipeline to our operations, and in connection with the purchase of assets from Link Energy LLC in April 2004, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations,

 

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including a Section 308 request received in late October 2007 with respect to a 400-barrel release of crude oil, a portion of which reached a tributary of the Colorado River in a remote area of West Texas.

 

At September 30, 2008, our reserve for environmental liabilities totaled approximately $46 million, of which approximately $13 million is classified as short-term and $33 million is classified as long-term. At September 30, 2008, we have recorded receivables totaling approximately $5 million for amounts that are probable of recovery under insurance and from third parties under indemnification agreements.

 

In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional claims. Therefore, although we believe that the reserve is adequate, costs incurred in excess of this reserve may be higher and may potentially have a material 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, natural disaster or terrorist activity. 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 overall trend in the environmental insurance industry 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 environmental 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 environmental activities or incorporate higher retention in our insurance arrangements.

 

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. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, although we believe that we have established adequate reserves to the extent that such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

 

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Table of Contents

 

Note 13—Operating Segments

 

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Marketing. The following table reflects certain financial data for each segment for the periods indicated (in millions):

 

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Table of Contents

 

 

 

Transportation (1)

 

Facilities

 

Marketing (1)

 

Total

 

Three Months Ended September 30, 2008

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

External Customers

 

$

147

 

$

39

 

$

8,676

 

$

8,862

 

Intersegment (2)

 

95

 

30

 

 

125

 

Total revenues of reportable segments

 

$

242

 

$

69

 

$

8,676

 

$

8,987

 

 

 

 

 

 

 

 

 

 

 

Equity earnings of unconsolidated entities

 

$

1

 

$

3

 

$

 

$

4

 

 

 

 

 

 

 

 

 

 

 

Segment profit (3) (4) (5)

 

$

119

 

$

39

 

$

138

 

$

296

 

 

 

 

 

 

 

 

 

 

 

SFAS 133 gain (3)

 

$

 

$

 

$

163

 

$

163

 

 

 

 

 

 

 

 

 

 

 

Maintenance capital

 

$

13

 

$

5

 

$

1

 

$

19

 

 

Three Months Ended September 30, 2007

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

External Customers

 

$

107

 

$

31

 

$

5,661

 

$

5,799

 

Intersegment (2)

 

91

 

23

 

7

 

121

 

Total revenues of reportable segments

 

$

198

 

$

54

 

$

5,668

 

$

5,920

 

 

 

 

 

 

 

 

 

 

 

Equity earnings of unconsolidated entities

 

$

2