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, 2009

 

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
incorporation or organization)

 

(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)

 

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. xYes  oNo

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  xYes  oNo

 

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 the 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 5, 2009, there were outstanding 136,135,988 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, 2009 and December 31, 2008

 

3

Condensed Consolidated Statements of Operations: For the three months and nine months ended September 30, 2009 and 2008

 

4

Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2009 and 2008

 

5

Condensed Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2009 and 2008

 

6

Condensed Consolidated Statements of Comprehensive Income: For the three months and nine months ended September 30, 2009 and 2008

 

6

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2009

 

6

Notes to the Condensed Consolidated Financial Statements

 

7

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

 

31

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

44

Item 4. CONTROLS AND PROCEDURES

 

44

PART II. OTHER INFORMATION

 

45

Item 1. LEGAL PROCEEDINGS

 

45

Item 1A. RISK FACTORS

 

45

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

 

45

Item 3. DEFAULTS UPON SENIOR SECURITIES

 

45

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

 

45

Item 5. OTHER INFORMATION

 

45

Item 6. EXHIBITS

 

46

SIGNATURES

 

50

 

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,

 

 

 

2009

 

2008

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

16

 

$

11

 

Trade accounts receivable and other receivables, net

 

1,641

 

1,525

 

Inventory

 

1,174

 

801

 

Other current assets

 

193

 

259

 

Total current assets

 

3,024

 

2,596

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

7,037

 

5,727

 

Accumulated depreciation

 

(840

)

(668

)

 

 

6,197

 

5,059

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Linefill and base gas

 

479

 

425

 

Long-term inventory

 

129

 

139

 

Investment in unconsolidated entities

 

68

 

257

 

Goodwill

 

1,270

 

1,210

 

Other, net

 

326

 

346

 

Total assets

 

$

11,493

 

$

10,032

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

1,827

 

$

1,507

 

Short-term debt (Note 6)

 

692

 

1,027

 

Other current liabilities

 

340

 

426

 

Total current liabilities

 

2,859

 

2,960

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Long-term debt under credit facilities and other

 

7

 

40

 

Senior notes, net of unamortized net discount of $15 and $6, respectively

 

4,135

 

3,219

 

Other long-term liabilities and deferred credits

 

265

 

261

 

Total long-term liabilities

 

4,407

 

3,520

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (136,135,988 and 122,911,645 units outstanding, respectively)

 

4,066

 

3,469

 

General partner

 

97

 

83

 

Total partners’ capital excluding noncontrolling interest

 

4,163

 

3,552

 

Noncontrolling interest

 

64

 

 

Total partners’ capital

 

4,227

 

3,552

 

Total liabilities and partners’ capital

 

$

11,493

 

$

10,032

 

 

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

 

3



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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

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

 

 

(unaudited)

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

Sales and related revenues

 

$

4,645

 

$

8,676

 

$

11,876

 

$

24,593

 

Pipeline tariff activities, trucking and related revenues

 

147

 

147

 

401

 

416

 

Storage, terminalling, processing and related revenues

 

65

 

39

 

165

 

109

 

Total revenues

 

4,857

 

8,862

 

12,442

 

25,118

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

4,417

 

8,369

 

11,036

 

23,929

 

Field operating costs

 

163

 

162

 

474

 

458

 

General and administrative expenses

 

52

 

39

 

153

 

130

 

Depreciation and amortization

 

59

 

49

 

173

 

150

 

Total costs and expenses

 

4,691

 

8,619

 

11,836

 

24,667

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

166

 

243

 

606

 

451

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

5

 

4

 

13

 

11

 

Interest expense (net of capitalized interest of $4, $4, $9 and $14, respectively)

 

(59

)

(52

)

(165

)

(143

)

Other income/(expense), net

 

12

 

14

 

17

 

27

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

124

 

209

 

471

 

346

 

Current income tax expense

 

(2

)

(3

)

(5

)

(9

)

Deferred income tax benefit

 

 

 

4

 

2

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

122

 

206

 

470

 

339

 

Less: Net income attributable to noncontrolling interest

 

 

 

(1

)

 

NET INCOME ATTRIBUTABLE TO PLAINS

 

$

122

 

$

206

 

$

469

 

$

339

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PLAINS:

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

88

 

$

173

 

$

370

 

$

256

 

GENERAL PARTNER

 

$

34

 

$

33

 

$

99

 

$

83

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.65

 

$

1.42

 

$

2.84

 

$

2.10

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.65

 

$

1.41

 

$

2.82

 

$

2.08

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

130

 

123

 

128

 

120

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

131

 

124

 

129

 

121

 

 

The accompanying notes are an integral part of these unaudited 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,

 

 

 

2009

 

2008

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

470

 

$

339

 

Reconciliation of net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation and amortization

 

173

 

150

 

Equity compensation charge

 

47

 

27

 

Inventory valuation adjustment

 

 

65

 

Gain on sale of investment assets

 

 

(12

)

Net gain on purchase of remaining 50% interest in PNGS

 

(9

)

 

Net cash paid for terminated interest rate and foreign currency hedging instruments

 

(9

)

(2

)

Equity earnings in unconsolidated entities, net of distributions

 

(6

)

(4

)

Other

 

(19

)

(9

)

Changes in assets and liabilities, net of acquisitions:

 

 

 

 

 

Trade accounts receivable and other

 

52

 

(410

)

Inventory

 

(349

)

(521

)

Accounts payable and other liabilities

 

(3

)

616

 

Net cash provided by operating activities

 

347

 

239

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(117

)

(662

)

Additions to property, equipment and other

 

(354

)

(446

)

Investment in unconsolidated entities

 

(4

)

(35

)

Cash received for sale of noncontrolling interest in a subsidiary

 

26

 

 

Net cash received/(paid) for linefill

 

8

 

(8

)

Proceeds from the sale of assets and other

 

4

 

36

 

Net cash used in investing activities

 

(437

)

(1,115

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net borrowings/(repayments) on revolving credit facility

 

(454

)

259

 

Net borrowings/(repayments) on hedged inventory facility

 

(180

)

111

 

Repayment of PNGS debt

 

(446

)

 

Proceeds from the issuance of senior notes (Note 6)

 

1,346

 

597

 

Repayments of senior notes

 

(175

)

 

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

 

458

 

315

 

Distributions paid to common unitholders (Note 8)

 

(344

)

(308

)

Distributions paid to general partner (Note 8)

 

(98

)

(84

)

Other financing activities

 

(9

)

(4

)

Net cash provided by financing activities

 

98

 

886

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(3

)

3

 

Net increase in cash and cash equivalents

 

5

 

13

 

Cash and cash equivalents, beginning of period

 

11

 

24

 

Cash and cash equivalents, end of period

 

$

16

 

$

37

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

150

 

$

143

 

 

 

 

 

 

 

Cash paid for income taxes

 

$

7

 

$

8

 

 

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

 

5



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

 

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

 

 

 

 

Common Units

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Units

 

Amount

 

Partner

 

Interest

 

Interest

 

Capital

 

 

 

(unaudited)

 

Balance, December 31, 2008

 

123

 

$

3,469

 

$

83

 

$

3,552

 

$

 

$

3,552

 

Sale of noncontrolling interest in a subsidiary

 

 

(36

)

(1

)

(37

)

63

 

26

 

Net income

 

 

370

 

99

 

469

 

1

 

470

 

Issuance of common units

 

11

 

447

 

9

 

456

 

 

456

 

Issuance of common units in connection with the PNGS Acquisition

 

2

 

91

 

2

 

93

 

 

93

 

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

 

 

12

 

 

12

 

 

12

 

Distributions

 

 

(344

)

(98

)

(442

)

 

(442

)

Class B Units of Plains AAP, L.P.

 

 

1

 

2

 

3

 

 

3

 

Other comprehensive income

 

 

56

 

1

 

57

 

 

57

 

Balance, September 30, 2009

 

136

 

$

4,066

 

$

97

 

$

4,163

 

$

64

 

$

4,227

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

 

 

(unaudited)

 

(unaudited)

 

Net income attributable to Plains

 

$

122

 

$

206

 

$

469

 

$

339

 

Other comprehensive income/(loss)

 

210

 

(4

)

57

 

(50

)

Comprehensive income

 

$

332

 

$

202

 

$

526

 

$

289

 

 

CONDENSED CONSOLIDATED STATEMENT OF
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

 

 

Derivative

 

Translation

 

 

 

 

 

 

 

Instruments

 

Adjustments

 

Other

 

Total

 

 

 

(unaudited)

 

Balance, December 31, 2008

 

$

161

 

$

(86

)

$

 

$

75

 

 

 

 

 

 

 

 

 

 

 

Reclassification adjustments

 

(19

)

 

 

(19

)

Changes in fair value of outstanding hedge positions

 

(61

)

 

 

(61

)

Deferred gains/(losses) on settled hedges, net

 

(27

)

 

 

(27

)

Currency translation adjustment

 

 

165

 

 

165

 

Proportionate share of our unconsolidated entities’ other comprehensive loss

 

 

 

(1

)

(1

)

Total period activity

 

(107

)

165

 

(1

)

57

 

 

 

 

 

 

 

 

 

 

 

Balance, September 30, 2009

 

$

54

 

$

79

 

$

(1

)

$

132

 

 

The accompanying notes are an integral part of these unaudited 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.

 

We are engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products.  We refer to liquefied petroleum gas and other natural gas-related petroleum products collectively as “LPG.”  We are also engaged in the development and operation of natural gas storage facilities.  We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Marketing.  See Note 13.

 

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2008 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 (“SEC”). 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 condensed balance sheet data as of December 31, 2008 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.  The results of operations for the three and nine months ended September 30, 2009 should not be taken as indicative of the results to be expected for the full year.

 

Subsequent events have been evaluated through the financial statements issuance date of November 6, 2009 and have been included within the following footnotes where applicable.

 

Note 2—Recent Accounting Pronouncements

 

Standards Adopted as of July 1, 2009

 

In June 2009, the Financial Accounting Standards Board (“FASB”) issued the FASB Accounting Standards Codification (the “Codification”) to establish a single source of authoritative nongovernmental U.S. generally accepted accounting principles (“U.S. GAAP”).  The Codification is meant to (i) simplify user access by codifying all authoritative U.S. GAAP into one location, (ii) ensure that codified content accurately represents authoritative U.S. GAAP and (iii) create a better structure and research system for U.S. GAAP.  The Codification was effective for interim or annual periods ending after September 15, 2009; therefore, we adopted this guidance as of July 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

Standards Adopted as of April 1, 2009

 

In May 2009, the FASB issued guidance that establishes general standards of accounting for and disclosure of subsequent events or events that occur after the balance sheet date but before financial statements are issued.  This guidance sets forth (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date.  This guidance was effective for interim or annual periods ending after June 15, 2009; therefore, we adopted this guidance as of April 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

In April 2009, the FASB issued guidance that increases the frequency of fair value disclosures from annual to quarterly in an effort to provide financial statement users with more timely and transparent information about the effects of current market conditions on financial instruments. This is intended to address concerns raised by some financial statement users about the lack of comparability resulting from the use of different measurement attributes for financial instruments. These disclosures are also intended to stimulate more robust discussions about financial instrument valuations between users and reporting entities. We adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

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Standards Adopted as of January 1, 2009

 

In November 2008, the FASB issued guidance that addresses certain accounting considerations, including initial measurement, decreases in investment value, and changes in the level of ownership or degree of influence related to equity method investments. We adopted this guidance as of January 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

In April 2008, the FASB issued guidance that 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 previous guidance over goodwill and other intangible assets. The intent of this guidance is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset under U.S. GAAP. We adopted this guidance as of January 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

In March 2008, the FASB issued guidance that addresses the application of the two-class method in determining income per unit for master limited partnerships (“MLPs”) having multiple classes of securities that may participate in partnership distributions. The two-class method is an earnings allocation formula that determines earnings per unit for each class of common units and participating securities according to participation rights in undistributed earnings. We adopted this guidance as of January 1, 2009.  This guidance has been applied retrospectively for all financial statement periods presented.  Adoption impacted the net income available to limited partners used in our computation of earnings per unit, but did not impact our net income, distributions to limited partners, financial position, results of operations or cash flows.  See Note 7 for additional disclosure.

 

Note 3—Trade Accounts Receivable

 

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, 2009 and December 31, 2008, substantially all of our net accounts receivable were less than 30 days past their scheduled invoice date.  Our allowance for doubtful accounts receivable totaled $9 million and $5 million at September 30, 2009 and December 31, 2008, respectively.  Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

At September 30, 2009 and December 31, 2008, we had received approximately $153 million and $66 million, respectively, of advance cash payments from third parties to mitigate credit and performance risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit and performance risk.

 

Note 4—Acquisitions

 

The following acquisitions were accounted for using the acquisition method of accounting and the purchase price was allocated in accordance with such method.

 

PNGS Acquisition

 

On September 3, 2009, we acquired the remaining 50% indirect interest in PAA Natural Gas Storage, LLC (“PNGS”) for an aggregate purchase price of $215 million (“PNGS Acquisition”). As a result of the transaction, we now own 100% of PNGS’ natural gas storage business and related operating entities, which are accounted for on a consolidated basis beginning in September 2009. We historically accounted for our 50% indirect interest in PNGS under the equity method. We recorded a net gain of approximately $9 million, recorded in other income, in connection with (i) adjusting our previously owned 50% investment in PNGS to fair value and (ii) terminating an agreement to supply natural gas to PNGS.

 

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PNGS owns and operates a total of approximately 40 billion cubic feet (“Bcf”) of natural gas storage capacity at its Bluewater facility in Michigan and Pine Prairie facility in Louisiana. The Bluewater facility is comprised of two separate Niagaran reef reservoirs with a capacity of approximately 26 Bcf. At the Pine Prairie facility, 14 Bcf of high-deliverability salt-cavern storage capacity has been placed in service and an additional 10 Bcf is under construction.  Pine Prairie Energy Center, LLC has received approvals from the Federal Energy Regulatory Commission and the Louisiana Department of Natural Resources to increase the permitted capacity at Pine Prairie to 48 Bcf.  The gas storage operations are reflected in our facilities segment.

 

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

 

Cash

 

$

90

 

PAA equity

 

91

 

Paid at closing

 

181

 

Fair value of contingent consideration (1)

 

34

 

Total purchase price

 

$

215

 

 


(1)             The deferred contingent cash consideration is payable in cash in two installments of $20 million each upon the achievement of certain performance milestones and events expected to occur over the next several years. The fair value of the deferred contingent cash consideration was based on a discounted cash flow model utilizing a discount rate of approximately 9%.

 

The allocation of fair value to the assets and liabilities acquired in the PNGS Acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired. The preliminary fair value allocation is as follows (in millions):

 

Property, plant and equipment

 

$

791

 

Base gas

 

28

 

Goodwill

 

26

 

Intangible assets

 

23

 

Working capital and other long-term assets and liabilities

 

8

 

Debt

 

(446

)

Total

 

$

430

 

 

Other Acquisitions

 

During the first nine months of 2009, we completed three other acquisitions for aggregate consideration of approximately $66 million. These acquisitions included (i) a crude oil pipeline that is reflected in the our transportation segment, (ii) a natural gas processing business that is reflected in our facilities segment and (iii) a refined products terminal that is reflected in our facilities segment. In connection with these transactions, we allocated approximately $9 million to goodwill.

 

In October 2009, we completed an acquisition for approximately $40 million. The assets acquired include six crude oil storage tanks (with a total of approximately 400,000 barrels of storage capacity), three receiving pipelines, a manifold system and various other related assets in Tulsa, Oklahoma. In conjunction with this acquisition, the seller entered into a 15-year tank lease and minimum throughput agreement with us (with options to extend the lease and throughput agreement).

 

Note 5—Inventory, Linefill and Base Gas and Long-term Inventory

 

Inventory, linefill and base gas and long-term inventory consisted of the following (barrels in thousands and cubic feet in millions, and total value in millions):

 

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Table of Contents

 

 

 

September 30, 2009

 

December 31, 2008

 

 

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

12,418

 

barrels

 

$

822

 

$

66.19

 

9,986

 

barrels

 

$

421

 

$

42.16

 

LPG

 

9,252

 

barrels

 

340

 

$

36.75

 

7,748

 

barrels

 

370

 

$

47.75

 

Refined products

 

128

 

barrels

 

9

 

$

70.31

 

103

 

barrels

 

5

 

$

48.54

 

Natural gas (2)

 

244

 

cubic feet

 

1

 

$

3.74

 

 

cubic feet

 

 

N/A

 

Parts and supplies

 

N/A

 

 

 

2

 

N/A

 

N/A

 

 

 

5

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,174

 

 

 

 

 

 

 

801

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,190

 

barrels

 

449

 

$

48.86

 

9,148

 

barrels

 

422

 

$

46.13

 

Natural gas (2) (3)

 

9,194

 

cubic feet

 

28

 

$

3.03

 

 

cubic feet

 

 

N/A

 

LPG

 

58

 

barrels

 

2

 

$

34.48

 

67

 

barrels

 

3

 

$

44.78

 

Linefill and base gas

 

 

 

 

 

479

 

 

 

 

 

 

 

425

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,651

 

barrels

 

113

 

$

68.44

 

1,781

 

barrels

 

121

 

$

67.94

 

LPG

 

458

 

barrels

 

16

 

$

34.93

 

363

 

barrels

 

18

 

$

49.59

 

Long-term inventory subtotal

 

 

 

 

 

129

 

 

 

 

 

 

 

139

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

1,782

 

 

 

 

 

 

 

$

1,365

 

 

 

 


(1)             Price per unit represents a weighted average associated with various grades, qualities, and locations; accordingly, these prices may not be comparable to published benchmarks for such products.

(2)             To account for the 6:1 mcf of natural gas to crude oil barrel ratio, the natural gas volumes can be converted to barrels by dividing by 6.

(3)             Natural gas-base gas consists of natural gas necessary to operate our storage facilities and may fluctuate based on the utilization of the caverns and reservoirs.

 

Note 6—Debt

 

Debt consists of the following (in millions):

 

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Table of Contents

 

 

 

September 30,

 

December 31,

 

 

 

2009

 

2008

 

Short-term debt:

 

 

 

 

 

Senior secured hedged inventory facility bearing interest at a rate of 2.0% and 2.3% as of September 30, 2009 and December 31, 2008, respectively

 

$

100

 

$

280

 

Senior unsecured revolving credit facility, bearing interest at a rate of 0.8% and 1.1% as of September 30, 2009 and December 31, 2008, respectively (1)

 

336

 

746

 

Senior notes, including unamortized premium (2) (3)

 

255

 

 

Other

 

1

 

1

 

Total short-term debt

 

692

 

1,027

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

4.75% senior notes due August 2009 (4)

 

 

175

 

4.25% senior notes due September 2012 (5)

 

500

 

 

7.75% senior notes due October 2012

 

200

 

200

 

5.63% senior notes due December 2013

 

250

 

250

 

7.13 % senior notes due June 2014 (3)

 

 

250

 

5.25% senior notes due June 2015

 

150

 

150

 

6.25% senior notes due September 2015

 

175

 

175

 

5.88% senior notes due August 2016

 

175

 

175

 

6.13% senior notes due January 2017

 

400

 

400

 

6.50% senior notes due May 2018

 

600

 

600

 

8.75% senior notes due May 2019

 

350

 

 

5.75% senior notes due January 2020

 

500

 

 

6.70% senior notes due May 2036

 

250

 

250

 

6.65% senior notes due January 2037

 

600

 

600

 

Unamortized premium/(discount), net

 

(15

)

(6

)

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

 

7

 

40

 

Total long-term debt (1) (2)

 

4,142

 

3,259

 

Total debt

 

$

4,834

 

$

4,286

 

 


(1)             As of September 30, 2009 and December 31, 2008, we have classified $336 million and $746 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.

 

(2)             Our fixed rate senior notes have a face value of approximately $4.4 billion as of September 30, 2009. We estimate the aggregate fair value of these notes as of September 30, 2009 to be approximately $4.7 billion.  Our fixed-rate senior notes are traded among institutions, which trades are routinely published by a reporting service.  Our determination of fair value is based on reported trading activity near quarter end.

 

(3)             On September 4, 2009, we gave irrevocable notice to redeem all of our outstanding $250 million 7.13% senior notes due 2014. After the 30-day notice period, the notes were redeemed on October 5, 2009.  Therefore, these notes (including the unamortized premium) are classified as short-term debt on our balance sheet.  In conjuction with the early redemption, we will recognize a loss of approximately $4 million.

 

(4)             We repaid our $175 million 4.75% senior notes on August 15, 2009.

 

(5)             These notes were issued in July 2009 and the proceeds are being used to supplement capital available from our hedged inventory facility.  At September 30, 2009, approximately $437 million had been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities.

 

Senior Notes

 

In September 2009, we completed the issuance of $500 million of 5.75% senior notes due January 15, 2020.  The senior notes were sold at 99.523% of face value.  Interest payments are due on January 15 and July 15 of each year, beginning on January 15, 2010.  We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities, a portion of which was used to fund the cash requirements of the PNGS Acquisition (which included repayment of all of PNGS’s debt).  See Note 4 for further discussion of the PNGS Acquisition.

 

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Table of Contents

 

In July 2009, we completed the issuance of $500 million of 4.25% senior notes due September 1, 2012.  The senior notes were sold at 99.802% of face value.  Interest payments are due on March 1 and September 1 of each year, beginning on March 1, 2010.  We used the net proceeds from this offering to supplement the capital available under our existing hedged inventory facility to fund working capital needs associated with base levels of routine foreign crude oil import and for seasonal LPG inventory requirements.  Concurrent with the issuance of these senior notes, we entered into interest rate swaps whereby we receive fixed payments at 4.25% and pay three-month LIBOR plus a spread on a notional principal amount of $150 million maturing in two years and an additional $150 million notional principal amount maturing in three years.

 

In April 2009, we completed the issuance of $350 million of 8.75% senior notes due May 1, 2019.  The senior notes were sold at 99.994% of face value.  Interest payments are due on May 1 and November 1 of each year, beginning on November 1, 2009.  We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities.

 

Credit Facilities

 

In October 2009, we renewed our 364-day committed hedged inventory credit facility, which matures in October 2010. The new committed facility replaced a similar $525 million facility that was scheduled to mature on November 5, 2009. The new facility has a borrowing capacity of $500 million, which may be increased to $1.2 billion, subject to obtaining additional lender commitments. Borrowings under this facility will be used to finance the purchase of hedged crude oil inventory for storage activities as well as for foreign import activities.

 

Letters of Credit

 

In connection with our crude oil marketing, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil.  At September 30, 2009 and December 31, 2008, we had outstanding letters of credit of approximately $66 million and $51 million, respectively.

 

Note 7—Net Income per Limited Partner Unit

 

Basic and diluted net income per unit is determined by dividing our limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period.  Pursuant to guidance issued by the FASB on the application of the two-class method for MLPs, the limited partners’ interest in net income is calculated by first reducing net income by the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter (including the incentive distribution interest in excess of the 2% general partner interest).  Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.  The adoption of this guidance resulted in a change to our calculation of earnings per unit by using distributions applicable to the period rather than distributions paid in the period (applicable to the previous period).  Also, in accordance with this guidance, earnings per unit for prior periods were recast to conform to this revised calculation.

 

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, 2009 and 2008 (amounts in millions, except per unit data):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

Net income

 

$

122

 

$

206

 

$

469

 

$

339

 

Less: General partner’s incentive distribution paid (1)

 

(32

)

(30

)

(92

)

(78

)

Subtotal

 

90

 

176

 

377

 

261

 

Less: General partner 2% ownership (1)

 

(2

)

(3

)

(7

)

(5

)

Net income available to limited partners

 

88

 

173

 

370

 

256

 

Adjustment in accordance with application of the two-class method for MLPs (1)

 

(3

)

2

 

(8

)

(5

)

Net income available to limited partners in accordance with the application of the two-class method for MLPs

 

$

85

 

$

175

 

$

362

 

$

251

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

130

 

123

 

128

 

120

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

131

 

124

 

129

 

121

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.65

 

$

1.42

 

$

2.84

 

$

2.10

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.65

 

$

1.41

 

$

2.82

 

$

2.08

 

 

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Table of Contents

 


(1)             We allocate net income to our general partner based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest).  Guidance issued by the FASB requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized in the earnings per unit calculation.  We reflect the impact of this difference as the “Adjustment in accordance with application of the two-class method for MLPs.”

 

(2)             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. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

 

Note 8—Partners’ Capital and Distributions

 

Equity Offerings

 

During the nine months ended September 30, 2009 and 2008, we completed the following equity offerings of our common units (in millions, except per unit data):

 

 

 

 

 

 

 

 

 

General

 

 

 

 

 

 

 

 

 

Gross

 

Proceeds

 

Partner

 

 

 

Net

 

Period

 

Units Issued

 

Unit Price

 

from Sale

 

Contribution

 

Costs (1)

 

Proceeds

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

September 2009

 

5,290,000

 

$

46.70

 

$

247

 

$

5

 

$

(6

)

$

246

 

March 2009

 

5,750,000

 

$

36.90

 

212

 

4

 

(6

)

210

 

 

 

11,040,000

 

 

 

$

459

 

$

9

 

$

(12

)

$

456

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

April 2008

 

6,900,000

 

$

46.31

 

$

320

 

$

6

 

$

(11

)

$

315

 

 


(1)             Costs include the gross spread paid to underwriters.

 

PNGS Acquisition

 

In September 2009, we issued 1,907,305 common units valued at approximately $91 million in order to satisfy a portion of the PNGS Acquisition purchase price. In conjunction with the issuance, we received a contribution from our general partner of approximately $2 million.  See Note 4 for further discussion.

 

LTIP Vesting

 

In May 2009, in connection with the settlement of vested LTIP awards, we issued 277,038 common units at a price of $41.23, for a fair value of approximately $12 million.

 

Distributions

 

The following table details the distributions pertaining to the first nine months of 2009 and 2008, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

 

 

 

 

 

Distributions Paid

 

Distributions

 

 

 

 

 

Common

 

General Partner

 

 

 

per limited

 

Date Declared

 

Date Paid or To Be Paid

 

Units Holders

 

Incentive

 

2%

 

Total

 

partner unit

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

October 19, 2009

 

November 13, 2009 (1)

 

$

125

 

$

35

 

$

3

 

$

163

 

$

0.9200

 

July 15, 2009

 

August 14, 2009

 

$

117

 

$

32

 

$

2

 

$

151

 

$

0.9050

 

April 8, 2009

 

May 15, 2009

 

$

117

 

$

32

 

$

2

 

$

151

 

$

0.9050

 

January 14, 2009

 

February 13, 2009

 

$

110

 

$

28

 

$

2

 

$

140

 

$

0.8925

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

October 22, 2008

 

November 14, 2008

 

$

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

 

 


(1)             Payable to unitholders of record on November 3, 2009, for the period July 1, 2009 through September 30, 2009.

 

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Table of Contents

 

Upon closing of the Pacific acquisition in November 2006 and the Rainbow acquisition in May 2008, our general partner agreed to reduce the amounts due it as incentive distributions. Additionally, in order to enhance our distribution coverage ratio over the next 24 months in connection with the PNGS Acquisition, our general partner has agreed to further reduce its incentive distributions by an aggregate of $8 million over the next two years - $1.25 million per quarter for the first four quarters and $0.75 million per quarter for the next four quarters. This incentive distribution reduction will become effective upon payment of our November 2009 quarterly distribution of $0.9200 per limited partner unit. The total reduction in incentive distributions related to the Pacific, Rainbow and PNGS acquisitions is $83 million. Following the distribution in November 2009, the aggregate incentive distribution reductions remaining will be approximately $23 million.

 

Note 9—Equity Compensation Plans

 

Long-Term Incentive Plans

 

For discussion of our Long-Term Incentive Plan (“LTIP”) awards, see Note 10 to our Consolidated Financial Statements included in our 2008 Annual Report on Form 10-K.  At September 30, 2009, the following LTIP awards were outstanding (units in millions):

 

 

 

Vesting

 

 

 

 

 

 

 

 

 

 

 

LTIP Units

 

Distribution

 

Estimated Unit Vesting Date

 

Outstanding

 

Amount

 

2009

 

2010

 

2011

 

2012

 

2013

 

0.6

(1)

$3.20

 

 

0.6

 

 

 

 

1.5

(2)

$3.50 - $4.50

 

 

0.1

 

0.8

 

0.5

 

0.1

 

1.7

(3)

$3.50 - $4.25

 

 

0.8

 

0.3

 

0.4

 

0.2

 

3.8

(4) (5)

 

 

 

1.5

 

1.1

 

0.9

 

0.3

 

 


(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 period.

 

(2)             These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.50 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained while the grantee remains employed by us, or the grantee does not meet the employment requirements, these awards will be forfeited. For purposes of this disclosure, the awards are presented above assuming that the distribution levels are attained, that all grantees remain employed by us through the vesting date, 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 $4.25.  For a majority of these LTIP awards, fifty percent will vest at specified dates regardless of whether the performance conditions are attained. 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.

 

(4)             Approximately 2 million of our approximately 3.8 million outstanding LTIP awards also include Distribution Equivalent Rights (“DERs”), of which 1 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):

 

 

 

 

 

Weighted Average

 

 

 

 

 

Grant Date

 

 

 

Units

 

Fair Value per Unit

 

Outstanding, December 31, 2008

 

3.9

 

$

36.44

 

Granted

 

0.5

 

$

31.18

 

Vested

 

(0.6

)

$

34.70

 

Cancelled or forfeited

 

(0.1

)

$

38.55

 

Acquired (1)

 

0.1

 

$

26.24

 

Outstanding, September 30, 2009

 

3.8

 

$

36.29

 

 


(1)             As a result of the PNGS Acquisition, LTIP awards that were granted to PNGS employees in prior years are now included in our consolidated outstanding LTIP awards.

 

14



Table of Contents

 

Our accrued liability at September 30, 2009 related to all outstanding LTIP awards and DERs is approximately $70 million, which includes an accrual associated with our assessment that an annualized distribution of $3.90 is probable of occurring (at this time, we have not deemed a distribution of more than $3.90 to be probable). At December 31, 2008, the accrued liability was approximately $55 million.

 

Class B Units of Plains AAP, L.P.

 

At September 30, 2009, 165,500 Class B units were outstanding, of which 38,500 units were earned. A total of 34,500 units were reserved for future grants. During the nine months ended September 30, 2009, 11,500 Class B units were issued to certain members of our senior management. These Class B units become earned in increments of 37.5%, 37.5% and 25% 180 days after us achieving annualized distribution levels of $3.75, $4.00 and $4.50, respectively.  The total grant date fair value of the 165,500 Class B units outstanding at September 30, 2009 was approximately $36 million of which approximately $1 million and $3 million was recognized as expense during the three months and nine months ended September 30, 2009, respectively. For further discussion of the Class B units, see Note 10 to our Consolidated Financial Statements included in our 2008 Annual Report on Form 10-K.

 

Other Consolidated Equity Compensation Information

 

We refer to our LTIP Plans and the Class B units collectively as “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,

 

 

 

2009

 

2008

 

2009

 

2008

 

Equity compensation expense

 

$

16

 

$

3

 

$

47

 

$

27

 

LTIP unit vestings

 

$

1

 

$

 

$

19

 

$

1

 

LTIP cash settled vestings

 

$

 

$

 

$

7

 

$

2

 

DER cash payments

 

$

1

 

$

1

 

$

3

 

$

3

 

 

Based on the September 30, 2009 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $53 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. This estimate is based on the closing market price of our units of $46.29 at September 30, 2009. Actual amounts may differ materially as a result of a change in the market price of our units 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) (2)

 

2009 (3)

 

$

9

 

2010

 

26

 

2011

 

12

 

2012

 

5

 

2013

 

1

 

Total

 

$

53

 

 


(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, 2009.

 

(2)             Includes unamortized fair value associated with Class B units of Plains AAP, L.P.

 

(3)             Includes equity compensation plan fair value amortization for the remaining three months of 2009.

 

Note 10—Derivatives and Risk Management Activities

 

We identify the risks that underlie our core business activities and utilize risk management strategies to mitigate those risks when we determine that there is value in doing so.  We use various derivative instruments to (i) manage our exposure to commodity price risk as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange-rate risk. Our policy is to use derivative instruments only for risk management purposes.  Our commodity risk management policies and procedures are designed to monitor NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity to help ensure that our hedging activities address our risks. Our interest rate and foreign currency risk management policies and procedures are designed to monitor our positions and ensure that those positions are

 

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consistent with our objectives and approved strategies.  Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. 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 used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.  A discussion of our derivative activities by risk category follows.

 

Commodity Price Risk Hedging

 

Our core business activities contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments.  Our policy is generally (i) to purchase only product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect the segment profit we earn, and (iii) not to acquire and hold physical inventory, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.  Although we seek to maintain a position that is substantially balanced within our marketing activities, we purchase crude oil, refined products and LPG from thousands of locations and may experience net unbalanced positions as a result of production, transportation and delivery variances, as well as logistical issues associated with inclement weather conditions and other uncontrollable events that occur within each month. In connection with our efforts to maintain a balanced position, our personnel are authorized to purchase or sell an aggregate limit of up to 810,000 barrels of crude oil, refined products and LPG relative to the volumes originally scheduled for such month, based on interim information.  The purpose of these purchases and sales is to manage risk as opposed to establishing a risk position. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time.

 

The material commodity related risks inherent in our business activities can be summarized into the following general categories:

 

Commodity Purchases and Sales — In the normal course of our marketing operations, we purchase and sell crude oil, LPG, and refined products.  We use derivatives to manage the associated risks and to optimize profits.  As of September 30, 2009, material net derivative positions related to these activities included:

 

·                  An approximate 195,000 barrel per day net long position (total of 5.9 million barrels) associated with our crude oil activities, which was unwound ratably during October 2009 to match monthly average pricing.

 

·                  An approximate 31,000 barrel per day (total of 13 million barrels) net short spread position which hedge a portion of our anticipated crude oil lease gathering purchases through November 2010. These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

 

·                  A net short position averaging approximately 14,500 barrels per day (total of 6.1 million barrels) of calendar spread call options for the period November 2009 through December 2010.  These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

 

·                  An average of approximately 3,100 barrels per day (total of 1.4 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are priced as a fixed percentage of WTI and continue through 2010.

 

·                  Approximately 17,100 barrels per day on average (total of 7.7 million barrels) of crude oil basis differential hedges, which run through 2010.

 

Storage Capacity Utilization — We own approximately 57 million barrels of crude oil, LPG and refined products storage capacity that is not used in our transportation operations.  This storage may be leased to third parties or utilized in our own marketing activities, including for the storage of inventory in a contango market. For capacity allocated to our marketing operations we have utilization risk if the market structure is backwardated. As of September 30, 2009, we used derivatives to manage the risk of not utilizing approximately 3 million barrels per month of storage capacity through 2011.  These positions are a combination of calendar spread options and NYMEX futures contracts.  These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

 

Inventory Storage — At times, we elect to purchase and store crude oil, LPG and refined products inventory in conjunction with our marketing activities.  These activities primarily relate to the seasonal storage of LPG inventories and contango market storage activities.  When we purchase and store barrels, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory.  As of September 30, 2009, we had approximately 9.5 million barrels of inventory hedged with derivatives.

 

We also purchase foreign cargoes of crude oil.  Concurrent with the purchase of foreign cargo inventory, we enter into derivatives to mitigate the price risk associated with the foreign cargo inventory between the time the foreign cargo is purchased and the ultimate sale of the foreign cargo.  As of September 30, 2009, we had approximately 4 million barrels of foreign cargo inventory hedged with

 

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derivatives.

 

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit.  We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs.  As of September 30, 2009, we had entered into a net short position consisting of crude oil futures and swaps to manage the risk associated with the anticipated sale of an average of approximately 2,300 barrels per day (total of 1.9 million barrels) from October 2009 through December 2011.  In addition, we had a long put option position of approximately 1 million barrels through December 2012 and a net long call option position of approximately 2 million barrels through December 2011, which provide upside price participation.

 

Diluent Purchases — We use diluent in our Canadian crude oil pipeline operations and have used derivative instruments to hedge the anticipated forward purchases of diluent and diluent inventory.  As of September 30, 2009, we had an average of 4,700 barrels per day of natural gasoline/WTI spread positions (approximately 3 million barrels) that run through mid-2011 and an average of 4,400 barrels per day of short crude oil futures (approximately 0.8 million barrels) to hedge condensate through the first quarter of 2010.

 

Natural Gas Purchases —  Our gas storage facilities require minimum levels of natural gas (“base gas”) to operate.  For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed.  We use derivatives to hedge anticipated purchases of natural gas.  As of September 30, 2009, we have a net long position of approximately 3 Bcf consisting of natural gas futures contracts through August 2010.

 

The derivative instruments we use consist primarily of futures, options and swaps traded on the NYMEX, ICE and in over-the-counter transactions.  Over-the-counter transactions include commodity swap and option contracts entered into with financial institutions and other energy companies.  All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into AOCI and recognized in revenues or 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 normal sale (“NPNS”) exclusion and thus are not subject to the accounting treatment for derivative instruments and hedging activities as set forth in FASB guidance. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the NPNS scope exception are recorded on the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

 

Interest Rate Risk Hedging

 

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and in certain cases, outstanding debt instruments.  The derivative instruments we use consist primarily of interest rate swaps and treasury locks.  As of September 30, 2009, AOCI includes deferred losses that relate to terminated interest rate swaps and treasury locks that were designated for hedge accounting.  These terminated interest rate derivatives were cash settled in connection with the issuance and refinancing of debt agreements over the previous five years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the forecasted debt instruments.

 

As of September 30, 2009, we had four outstanding interest rate swaps by which we receive fixed interest payments and pay floating-rate interest payments based on three-month LIBOR plus an aggregate spread of 2.42% on a semi-annual basis.  The swaps have an aggregate notional amount of $300 million with fixed rates of 4.25%.  Two of the swaps terminate in 2011 and two of the swaps terminate in 2012.

 

Currency Exchange Rate Risk Hedging

 

We use foreign currency derivatives to hedge foreign currency risk associated with our exposure to fluctuations in the U.S. Dollar (“USD”)-to-Canadian Dollar (“CAD”) exchange rate.  Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments primarily include forward exchange contracts and foreign currency forwards and options.  As of September 30, 2009, AOCI includes deferred gains that relate to open and settled forward exchange contracts that were designated for hedge accounting.  These forward exchange contracts hedge the cash flow variability associated with CAD-denominated interest payments on a CAD-denominated intercompany note as a result of changes in the foreign exchange rate.

 

As of September 30, 2009, our outstanding foreign currency derivatives also include derivatives used to hedge CAD-denominated crude oil purchases and sales.  We may from time to time hedge the commodity price risk associated with a CAD-denominated commodity transaction with a USD-denominated commodity derivative.  In conjunction with entering into the commodity derivative we enter into a foreign currency derivative to hedge the resulting foreign currency risk.  These foreign currency derivatives are generally short-term in nature and are not designated for hedge accounting.

 

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At September 30, 2009, our open foreign exchange derivatives consisted of forward exchange contracts that exchange CAD for USD on a net basis as follows (in millions):

 

 

 

CAD

 

USD

 

Average Exchange Rate

 

2009

 

$

18

 

$

15

 

CAD $1.15 to US $1.00

 

2010

 

$

43

 

$

39

 

CAD $1.14 to US $1.00

 

2011

 

$

15

 

$

15

 

CAD $1.01 to US $1.00

 

2012

 

$

15

 

$

15

 

CAD $1.01 to US $1.00

 

2013

 

$

9

 

$

9

 

CAD $1.00 to US $1.00

 

 

These financial instruments are placed with large, highly rated financial institutions.

 

Summary of Financial Impact

 

The majority of our derivative activity relates to our commodity price risk hedging activities. All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of the hedged items, are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as operating cash flows in our consolidated statements of cash flows.

 

A summary of the impact of our derivative activities recognized in earnings for the three and nine months ended September 30, 2009 is as follows (in millions, losses designated in parentheses):

 

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DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS:

 

Three Months Ended September 30, 2009:

 

 

 

 

 

Derivatives in Cash Flow

 

 

 

 

 

 

 

 

 

Hedging Relationships

 

Derivatives Not

 

 

 

 

 

 

 

AOCI

 

Inneffective

 

Designated

 

 

 

 

 

Location of gain/(loss)

 

Reclass (1)

 

Portion (2)

 

as a Hedge (3)

 

Total

 

Commodity contracts

 

Sales and related revenues

 

$

(159

)

$

 

$

11

 

$

(146

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

60

 

 

4

 

64

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Contracts

 

Interest expense

 

 

 

1

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Exchange Contracts

 

Sales and related revenues 

 

 

 

4

 

4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs 

 

 

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income/(expense), net

 

 

 

(1

)

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

Total Gain/(Loss) Recognized in Income from Derivatives

 

$

(99

)

$

2

 

$

21

 

$

(76

)

 


(1)  Amounts represent derivative gains and (losses) that were reclassed from AOCI to earnings during the period to coincide with earnings impact of the respective hedged transaction

(2)  Amounts represent the ineffective portion of the fair value of our unrealized cash flow hedges that was recognized in earnings during the period.

(3)  Amounts include the mark-to-market earnings impact for unrealized derivatives not designated for hedge accounting during the period.

 

Nine Months Ended September 30, 2009:

 

 

 

 

 

Derivatives in Cash Flow

 

 

 

 

 

 

 

 

 

Hedging Relationships

 

Derivatives Not

 

 

 

 

 

 

 

AOCI

 

Inneffective

 

Designated

 

 

 

 

 

Location of gain/(loss)

 

Reclass (1)

 

Portion (2)

 

as a Hedge (3)

 

Total

 

Commodity contracts

 

Sales and related revenues

 

$

(14

)

$

(6

)

$

17

 

$

(3

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

29

 

 

119

 

148

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Contracts

 

Other income/(expense), net

 

 

 

(1

)

(1

)