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, 2010

 

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.    x  Yes     o  No

 

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).    x  Yes     o  No

 

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

 

As of November 1, 2010, there were 136,419,175 Common Units outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “PAA.”

 

 

 



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, 2010 and December 31, 2009

 

3

Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2010 and 2009

 

4

Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2010 and 2009

 

5

Condensed Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2010

 

6

Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2010 and 2009

 

6

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2010

 

6

Notes to the Condensed Consolidated Financial Statements:

 

7

1. Organization and Basis of Presentation

 

7

2. Recent Accounting Pronouncements

 

8

3. Trade Accounts Receivable

 

8

4. Inventory, Linefill, Base Gas and Long-term Inventory

 

9

5. Debt

 

10

6. Net Income Per Limited Partner Unit

 

11

7. Partners’ Capital and Distributions

 

12

8. Equity Compensation Plans

 

15

9. Derivatives and Risk Management Activities

 

16

10. Commitments and Contingencies

 

24

11. Operating Segments

 

26

12. Supplemental Condensed Consolidating Financial Information

 

28

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

 

34

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

47

Item 4. CONTROLS AND PROCEDURES

 

47

 

 

 

PART II. OTHER INFORMATION

 

48

Item 1. LEGAL PROCEEDINGS

 

48

Item 1A. RISK FACTORS

 

48

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

 

48

Item 3. DEFAULTS UPON SENIOR SECURITIES

 

48

Item 4. [REMOVED AND RESERVED]

 

48

Item 5. OTHER INFORMATION

 

48

Item 6. EXHIBITS

 

48

SIGNATURES

 

52

 

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,

 

 

 

2010

 

2009

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

13

 

$

25

 

Trade accounts receivable and other receivables, net

 

2,144

 

2,253

 

Inventory

 

1,556

 

1,157

 

Other current assets

 

58

 

223

 

Total current assets

 

3,771

 

3,658

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

7,599

 

7,240

 

Accumulated depreciation

 

(1,067

)

(900

)

 

 

6,532

 

6,340

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

1,294

 

1,287

 

Linefill and base gas

 

510

 

501

 

Long-term inventory

 

120

 

121

 

Investments in unconsolidated entities

 

204

 

82

 

Other, net

 

306

 

369

 

Total assets

 

$

12,737

 

$

12,358

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

2,485

 

$

2,295

 

Short-term debt

 

895

 

1,074

 

Other current liabilities

 

187

 

413

 

Total current liabilities

 

3,567

 

3,782

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discount of $13 and $14, respectively

 

4,362

 

4,136

 

Long-term debt under credit facilities and other

 

231

 

6

 

Other long-term liabilities and deferred credits

 

234

 

275

 

Total long-term liabilities

 

4,827

 

4,417

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 10)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (136,419,175 and 136,135,988 units outstanding, respectively)

 

4,014

 

4,002

 

General partner

 

97

 

94

 

Total partners’ capital excluding noncontrolling interests

 

4,111

 

4,096

 

Noncontrolling interests

 

232

 

63

 

Total partners’ capital

 

4,343

 

4,159

 

Total liabilities and partners’ capital

 

$

12,737

 

$

12,358

 

 

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

 

3



Table of Contents

 

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,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

(unaudited)

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

Supply & Logistics segment revenues

 

$

6,179

 

$

4,645

 

$

17,992

 

$

11,876

 

Transportation segment revenues

 

144

 

147

 

421

 

401

 

Facilities segment revenues

 

91

 

65

 

249

 

165

 

Total revenues

 

6,414

 

4,857

 

18,662

 

12,442

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

5,971

 

4,417

 

17,233

 

11,036

 

Field operating costs

 

176

 

163

 

510

 

474

 

General and administrative expenses

 

56

 

52

 

174

 

153

 

Depreciation and amortization

 

61

 

59

 

192

 

173

 

Total costs and expenses

 

6,264

 

4,691

 

18,109

 

11,836

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

150

 

166

 

553

 

606

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

1

 

5

 

3

 

13

 

Interest expense (net of capitalized interest of $4, $4, $13 and $9, respectively)

 

(64

)

(59

)

(183

)

(165

)

Other income/(expense), net

 

(7

)

12

 

(9

)

17

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

80

 

124

 

364

 

471

 

Current income tax benefit/(expense)

 

1

 

(2

)

 

(5

)

Deferred income tax benefit

 

3

 

 

4

 

4

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

84

 

122

 

368

 

470

 

Less: Net income attributable to noncontrolling interests

 

(3

)

 

(5

)

(1

)

NET INCOME ATTRIBUTABLE TO PLAINS:

 

$

81

 

$

122

 

$

363

 

$

469

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PLAINS:

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

40

 

$

88

 

$

241

 

$

370

 

GENERAL PARTNER

 

$

41

 

$

34

 

$

122

 

$

99

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.28

 

$

0.65

 

$

1.73

 

$

2.84

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.28

 

$

0.65

 

$

1.72

 

$

2.82

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

136

 

130

 

136

 

128

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

137

 

131

 

137

 

129

 

 

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

 

4



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2010

 

2009

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

368

 

$

470

 

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

 

 

 

 

 

Depreciation and amortization

 

192

 

173

 

Equity compensation charge

 

50

 

47

 

Gain on sale of linefill

 

(18

)

(4

)

Loss on early redemption of senior notes (Note 5)

 

6

 

 

Other

 

 

(39

)

Changes in assets and liabilities, net of acquisitions

 

(135

)

(300

)

Net cash provided by operating activities

 

463

 

347

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(197

)

(117

)

Additions to property, equipment and other

 

(323

)

(354

)

Cash received for sale of noncontrolling interest in a subsidiary

 

268

 

26

 

Net cash received for linefill

 

20

 

8

 

Investment in unconsolidated entities

 

 

(4

)

Other investing activities

 

5

 

4

 

Net cash used in investing activities

 

(227

)

(437

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net repayments on Plains revolving credit facility

 

(281

)

(454

)

Net borrowings on PNG revolving credit facility

 

222

 

 

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

 

100

 

(180

)

Repayment of PNGS debt

 

 

(446

)

Repayments of senior notes

 

(175

)

(175

)

Net proceeds from the issuance of senior notes

 

400

 

1,346

 

Net proceeds from the issuance of common units

 

 

458

 

Distributions paid to common unitholders (Note 7)

 

(382

)

(344

)

Distributions paid to general partner (Note 7)

 

(125

)

(98

)

Distributions to noncontrolling interests (Note 7)

 

(5

)

 

Other financing activities

 

(1

)

(9

)

Net cash provided by/(used in) financing activities

 

(247

)

98

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(1

)

(3

)

 

 

 

 

 

 

Net increase/(decrease) in cash and cash equivalents

 

(12

)

5

 

Cash and cash equivalents, beginning of period

 

25

 

11

 

Cash and cash equivalents, end of period

 

$

13

 

$

16

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

191

 

$

150

 

 

 

 

 

 

 

Cash paid for income taxes, net of amounts refunded

 

$

20

 

$

7

 

 

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

 

Interests

 

Interests

 

Capital

 

 

 

(unaudited)

 

Balance, December 31, 2009

 

136

 

$

4,002

 

$

94

 

$

4,096

 

$

63

 

$

4,159

 

Net income

 

 

241

 

122

 

363

 

5

 

368

 

Sale of noncontrolling interest in a subsidiary (Note 7)

 

 

99

 

2

 

101

 

167

 

268

 

Distributions (Note 7)

 

 

(382

)

(125

)

(507

)

(5

)

(512

)

Issuance of common units under LTIP (Note 7)

 

 

16

 

 

16

 

 

16

 

Other comprehensive income

 

 

36

 

1

 

37

 

 

37

 

Other

 

 

2

 

3

 

5

 

2

 

7

 

Balance, September 30, 2010

 

136

 

$

4,014

 

$

97

 

$

4,111

 

$

232

 

$

4,343

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

84

 

$

122

 

$

368

 

$

470

 

Other comprehensive income

 

17

 

210

 

37

 

57

 

Comprehensive income

 

101

 

332

 

405

 

527

 

Less: Comprehensive income attributable to noncontrolling interests

 

(3

)

 

(5

)

(1

)

Comprehensive income attributable to Plains

 

$

98

 

$

332

 

$

400

 

$

526

 

 

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

 

 

Derivative

 

Translation

 

 

 

 

 

 

 

Instruments

 

Adjustments

 

Other

 

Total

 

 

 

(unaudited)

 

Balance, December 31, 2009

 

$

18

 

$

106

 

$

(1

)

$

123

 

Reclassification adjustments

 

11

 

 

 

11

 

Net deferred loss on cash flow hedges

 

(6

)

 

 

(6

)

Currency translation adjustment

 

 

32

 

 

32

 

Total period activity

 

5

 

32

 

 

37

 

Balance, September 30, 2010

 

$

23

 

$

138

 

$

(1

)

$

160

 

 

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

 

6


 


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

 

Organization

 

We engage in the transportation, storage, terminalling and marketing of crude oil, refined products and LPG. We also engage in the development and operation of natural gas storage facilities. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 11 for further detail of our operating segments.

 

As used in this Form 10-Q, the terms “Partnership,” “Plains,” “PAA,” “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.

 

Definitions

 

The following additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:

 

AOCI

= Accumulated other comprehensive income

API 653

= American Petroleum Institute Standard 653

Bcf

= Billion cubic feet

CAA

= Clean Air Act

CAD

= Canadian Dollar

DCP

= Disclosure controls and procedures

DERs

= Distribution Equivalent Rights

DOJ

= United States Department of Justice

EPA

= United States Environmental Protection Agency

FERC

= Federal Energy Regulation Commission

FASB

= Financial Accounting Standards Board

ICE

= IntercontinentalExchange

IPO

= Initial Public Offering

LIBOR

= London Interbank Offered Rate

LPG

= Liquefied petroleum gas and other natural gas-related petroleum products

LTIP

= Long term incentive plan

Mcf

= Thousand cubic feet

MLP

= Master limited partnership

MTBE

= Methyl tertiary-butyl ether

NJDEP

= New Jersey Department of Environmental Protection

NYMEX

= New York Mercantile Exchange

NPNS

= Normal purchase and normal sale

PAA Class B units

= Class B units of our general partner, Plains AAP, L.P.

PLA

= Pipeline loss allowance

PNG

= PAA Natural Gas Storage, L.P.

PNG Class B units

= Class B units of PNG’s general partner, PNGS GP LLC

PNG Plan

= PAA Natural Gas Storage, L.P. 2010 Long Term Incentive Plan

PNGS

= PAA Natural Gas Storage, LLC

PAT

= Pacific Atlantic Terminals, LLC

Rainbow

= Rainbow Pipe Line Company Ltd.

RMPS

= Rocky Mountain Pipeline System

SEC

= Securities and Exchange Commission

U.S. GAAP

= United States generally accepted accounting principles

USD

= United States Dollar

WTI

= West Texas Intermediate

 

7



Table of Contents

 

Basis of Consolidation and Presentation

 

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2009 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the 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 in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to Plains. The condensed balance sheet data as of December 31, 2009 was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. The results of operations for the three and nine months ended September 30, 2010 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 and have been included within the following footnotes where applicable.

 

Note 2—Recent Accounting Pronouncements

 

Other than as discussed below and in our 2009 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the nine months ended September 30, 2010 that are of significance or potential significance to us.

 

Fair Value Measurement Disclosure Requirements. In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. A fair value measurement is designated as Level 1, 2 or 3 within the hierarchy based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, Level 2 measurements generally reflect the use of significant observable inputs and Level 3 measurements typically utilize significant unobservable inputs. This new guidance requires additional disclosures regarding transfers into and out of Level 1 and Level 2 measurements and requires a gross presentation of activities within the Level 3 roll forward. This guidance was effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance relating to Level 1 and Level 2 measurements as of January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations or cash flows. We will adopt the guidance relating to Level 3 measurements on January 1, 2011. We do not expect that adoption of this guidance will have any material impact on our financial position, results of operations, or cash flows.

 

Variable Interest Entities. In June 2009, the FASB issued guidance that requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest(s) provide a controlling financial interest in a variable interest entity (“VIE”). This analysis identifies the primary beneficiary of a VIE as the enterprise that has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could potentially be significant to the VIE. This guidance also (i) requires such assessments to be ongoing, (ii) amends certain guidance for determining whether an entity is a VIE and (iii) enhances disclosures that will provide users of financial statements with more transparent information regarding an enterprise’s involvement in a VIE. We adopted this guidance as of January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations or cash flows.

 

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. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At September 30, 2010 and December 31, 2009, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 60 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million and $9 million at September 30, 2010 and December 31, 2009, respectively. The decrease in our allowance for doubtful accounts receivable balance during the nine months ended September 30, 2010 primarily is due to the collection and related settlement of claims for receivables that had been reserved for during the years ended December 31, 2009 and 2008. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

At September 30, 2010 and December 31, 2009, we had received approximately $142 million and $212 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables between the two) that cover a significant part of our transactions and also serve to mitigate credit risk.

 

8



Table of Contents

 

Note 4—Inventory, Linefill, Base Gas and Long-term Inventory

 

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

 

 

 

September 30, 2010

 

December 31, 2009

 

 

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

14,556

 

barrels

 

$

1,066

 

$

73.23

 

12,232

 

barrels

 

$

886

 

$

72.43

 

LPG

 

9,627

 

barrels

 

462

 

$

47.99

 

6,051

 

barrels

 

247

 

$

40.82

 

Refined products

 

300

 

barrels

 

25

 

$

83.33

 

283

 

barrels

 

21

 

$

74.20

 

Natural gas (2)

 

114

 

mcf

 

1

 

$

3.58

 

181

 

mcf

 

1

 

$

3.30

 

Parts and supplies

 

N/A

 

 

 

2

 

N/A

 

N/A

 

 

 

2

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,556

 

 

 

 

 

 

 

1,157

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,166

 

barrels

 

468

 

$

51.06

 

9,404

 

barrels

 

471

 

$

50.09

 

Natural gas (2)

 

11,194

 

mcf

 

38

 

$

3.39

 

9,194

 

mcf

 

28

 

$

3.04

 

LPG

 

77

 

barrels

 

4

 

$

51.95

 

52

 

barrels

 

2

 

$

38.46

 

Linefill and base gas subtotal

 

 

 

 

 

510

 

 

 

 

 

 

 

501

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,420

 

barrels

 

97

 

$

68.31

 

1,497

 

barrels

 

103

 

$

68.80

 

LPG

 

544

 

barrels

 

23

 

$

42.28

 

458

 

barrels

 

18

 

$

39.30

 

Long-term inventory subtotal

 

 

 

 

 

120

 

 

 

 

 

 

 

121

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

2,186

 

 

 

 

 

 

 

$

1,779

 

 

 

 


(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)                      The volumetric ratio of mcf of natural gas to barrels of crude oil is 6:1; thus, natural gas volumes can be converted to barrels by dividing by 6.

 

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Note 5—Debt

 

Debt consisted of the following (in millions):

 

 

 

September 30,

 

December 31,

 

 

 

2010

 

2009

 

Short-term debt:

 

 

 

 

 

Senior secured hedged inventory facility bearing interest at a rate of 2.5% at both September 30, 2010 and December 31, 2009

 

$

400

 

$

300

 

Senior unsecured revolving credit facility, bearing interest at a rate of 0.7% and 0.8% at September 30, 2010 and December 31, 2009, respectively (1)

 

493

 

772

 

Other

 

2

 

2

 

Total short-term debt

 

895

 

1,074

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

4.25% senior notes due September 2012 (2)

 

500

 

500

 

7.75% senior notes due October 2012

 

200

 

200

 

5.63% senior notes due December 2013

 

250

 

250

 

5.25% senior notes due June 2015

 

150

 

150

 

3.95% senior notes due September 2015 (3)

 

400

 

 

6.25% senior notes due September 2015 (4)

 

 

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

 

350

 

5.75% senior notes due January 2020

 

500

 

500

 

6.70% senior notes due May 2036

 

250

 

250

 

6.65% senior notes due January 2037

 

600

 

600

 

Unamortized discount

 

(13

)

(14

)

Long-term debt under credit facilities and other (5)

 

231

 

6

 

Total long-term debt (1) (6)

 

4,593

 

4,142

 

Total debt

 

$

5,488

 

$

5,216

 

 


(1)                      We classify as short-term our borrowings under our senior unsecured revolving credit facility. 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 NYMEX and ICE margin deposits.

 

(2)                      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, 2010 and December 31, 2009, approximately $500 million and $222 million, respectively, had been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities.

 

(3)                      In July 2010, we completed the issuance of $400 million of 3.95% senior notes due September 15, 2015. The senior notes were sold at 99.889% of face value. Interest payments are due on March 15 and September 15 of each year, beginning on September 15, 2010. We used the net proceeds from this offering to repay outstanding indebtedness under our credit facilities.

 

(4)                      On September 15, 2010, our $175 million, 6.25% senior notes due 2015 were redeemed in full.  In conjunction with the early redemption, we recognized a loss of approximately $6 million. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

 

(5)                      In April 2010, our consolidated subsidiary PNG entered into a three year, $400 million senior unsecured revolving credit facility that matures in May 2013. This credit facility, which bears interest based on LIBOR plus an applicable margin (as defined by the credit agreement), may be expanded to $600 million, subject to additional lender commitments, with approval of the

 

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administrative agent for the credit facility. At September 30, 2010, borrowings of approximately $222 million were outstanding under this facility.

 

(6)                      Our fixed-rate senior notes have a face value of approximately $4.4 billion as of September 30, 2010. We estimate the aggregate fair value of these notes as of September 30, 2010 to be approximately $4.9 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.

 

Credit Facilities

 

In October 2010, we renewed our 364-day committed hedged inventory credit facility, which matures in October 2011. The 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 (i) the purchase of hedged crude oil inventory for storage activities and (ii) foreign import activities.

 

Letters of Credit

 

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. At September 30, 2010 and December 31, 2009, we had outstanding letters of credit of approximately $68 million and $76 million, respectively.

 

Note 6—Net Income 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, 2010 and 2009 (amounts in millions, except per unit data):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

81

 

$

122

 

$

363

 

$

469

 

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

 

(40

)

(32

)

(117

)

(92

)

Subtotal

 

41

 

90

 

246

 

377

 

Less: General partner 2% ownership (1)

 

(1

)

(2

)

(5

)

(7

)

Net income available to limited partners

 

40

 

88

 

241

 

370

 

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

 

(2

)

(3

)

(5

)

(8

)

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

 

$

38

 

$

85

 

$

236

 

$

362

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

136

 

130

 

136

 

128

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

137

 

131

 

137

 

129

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.28

 

$

0.65

 

$

1.73

 

$

2.84

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.28

 

$

0.65

 

$

1.72

 

$

2.82

 

 


(1)                      We calculate net income available to limited partners based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest). However, FASB guidance 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. After adjusting for this distribution, 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

 

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partnership agreement for earnings per unit calculation purposes. We reflect the impact of the difference in (i) the distribution utilized and (ii) the calculation of the excess 2% general partner interest as the “Adjustment in accordance with application of the two-class method for MLPs.”

(2)                      Our LTIP awards (described in Note 8) 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 7—Partners’ Capital and Distributions

 

Sale of Noncontrolling Interest in a Subsidiary

 

PNG Initial Public Offering

 

On May 5, 2010, PNG completed its IPO of 13,478,000 common units representing limited partner interests at $21.50 per common unit. The number of units issued at closing included 1,758,000 common units issued pursuant to the full exercise of the underwriters’ over-allotment option. Net proceeds received by PNG from the sale of the 13,478,000 common units were approximately $268 million and were used to repay amounts outstanding under our credit facilities and for general partnership purposes. The common units offered represent approximately 23% of the outstanding equity of PNG. We own the remaining 77% equity interest in PNG and control the entity, and therefore, continue to consolidate the financial results.

 

Prior to the PNG IPO, we owned 100% of PNGS’ natural gas storage business, the predecessor of PNG, and related operating entities. Immediately prior to the closing of the IPO, we contributed 100% of the equity interests in PNGS and its subsidiaries to PNG in exchange for approximately 18.1 million common units, approximately 13.9 million Series A subordinated units, 11.5 million Series B subordinated units and a 2% general partner interest and incentive distribution rights. In conjunction with the offering, we recorded non-controlling interest of $167 million associated with the book value of PNG sold to the public. We also recorded an increase to our partners’ capital of approximately $101 million associated with the net increase from our share of the proceeds received in the offering partially offset by the dilution of our interest in PNG resulting from the IPO.

 

PAA Modification of Holdings in PNG Subordinated Units

 

On August 16, 2010, the Amended and Restated Agreement of Limited Partnership of PNG was amended and restated (the “Second Amended and Restated Agreement”) to reduce the number of series A subordinated units by 2 million and increase the number of series B subordinated units by an equivalent amount.  The Second Amended and Restated Agreement also increased the number of potential conversion tranches on Series B subordinated units from three to five.  In addition, the terms of the Series B subordinated units were modified to extend the conversion period by raising the operating and financial performance benchmarks of approximately one-third of the Series B subordinated units outstanding prior to this modification. This amendment was intended to increase the distribution coverage and organic growth profile of PNG’s common and Series A subordinated units and improve PNG’s posture with respect to potential acquisitions.  We accounted for this transaction as an exchange between entities under common control and accordingly, we reclassified the book value of the 2.0 million Series A subordinated units at the time of the modification to Series B subordinated units.

 

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The following table sets forth the changes made to our holdings in the limited partner units of PNG from May 5, 2010 through September 30, 2010 (units in millions):

 

 

 

Prior to
Modification

 

Modification

 

Post
Modification

 

 

 

(in millions)

 

PNG Units Owned by PAA:

 

 

 

 

 

 

 

Common Units

 

18.1

 

 

18.1

 

Series A Subordinated Units

 

13.9

 

(2.0

)

11.9

 

Common & Series A Subordinated Unit Subtotal

 

32.0

 

(2.0

)

30.0

 

Series B Subordinated Units (Performance Thresholds):

 

 

 

 

 

 

 

Tranche 1 ($1.44 / 29.6 Bcf)

 

4.6

 

(2.0

)

2.6

 

Tranche 2 ($1.53 / 35.6 Bcf)

 

3.8

 

(1.0

)

2.8

 

Tranche 3 ($1.63 / 41.6 Bcf)

 

3.1

 

(1.0

)

2.1

 

Tranche 4 ($1.71 / 48.0 Bcf)

 

 

3.0

 

3.0

 

Tranche 5 ($1.80 / 48.0 Bcf)

 

 

3.0

 

3.0

 

Series B Subordinated Unit Subtotal

 

11.5

 

2.0

 

13.5

 

Total PNG Units Owned by PAA(1)

 

43.5

 

 

43.5

 

 


(1) See “PNG Transaction Grants” in Note 8.

 

Series A and Series B Subordinated Units.  The Series A subordinated units are not entitled to receive any distributions until the common units have received the minimum quarterly distribution ($1.35 on an annualized basis) plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The Series A subordinated units will convert to common units once certain earnings and distribution targets are met for three consecutive, non-overlapping four-quarter periods. The Series B subordinated units are not entitled to participate in quarterly distributions until they convert into Series A subordinated units. The Series B subordinated units will convert into Series A subordinated units upon satisfaction of the following operational and financial conditions:

 

·                  2,600,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 29.6 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.36 per unit (representing an annualized distribution of $1.44 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and (c) PNG makes a quarterly distribution of available cash of at least $0.36 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2.0% interest and the related distributions on the incentive distribution rights;

 

·                  2,833,333 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 35.6 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.3825 per unit (representing an annualized distribution of $1.53 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior bullet, and (c) PNG makes a quarterly distribution of available cash of at least $0.3825 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2.0% interest and the related distributions on the incentive distribution rights;

 

·                  2,066,667 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 41.6 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.4075 per unit (representing an annualized distribution of $1.63 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior two bullets, and (c) PNG makes a quarterly distribution of available cash of at least $0.4075 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2.0% interest and the related distributions on the incentive distribution rights; and

 

·                  3,000,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 48.0 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.4275 per unit (representing an annualized distribution of $1.71 per unit) on the weighted

 

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average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior three bullets, and (c) PNG makes a quarterly distribution of available cash of at least $0.4275 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2.0% interest and the related distributions on the incentive distribution rights; and

 

·                  3,000,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 48.0 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.45 per unit (representing an annualized distribution of $1.80 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior four bullets, and (c) PNG makes a quarterly distribution of available cash of at least $0.45 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2.0% interest and the related distributions on the incentive distribution rights.

 

PNG’s general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the operational tests described above are satisfied prior to or during the two-quarter period applicable to the financial tests described above, the holder of the Series B subordinated units subject to conversion will be entitled to receive the quarterly distribution payable with respect to the second quarter of such two-quarter period. In all other circumstances, where the operational tests are satisfied following the two-quarter period applicable to the financial tests, the holder of the Series B subordinated units subject to conversion will be entitled to receive any distribution payable following the satisfaction of such operational tests.

 

Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled.

 

Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.

 

If at the time the above operational and financial tests are satisfied, the subordination period has already ended and all outstanding Series A subordinated units have converted into common units, the Series B subordinated units will instead convert directly into common units on a one-for-one basis and participate in the quarterly distribution payable to common units.

 

Noncontrolling Interests Rollforward

 

The following table reflects the changes in the noncontrolling interests in partners’ capital (in millions):

 

 

 

For the Nine Months Ended September 30,

 

 

 

2010

 

2009

 

Beginning balance

 

$

63

 

$

 

Sale of noncontrolling interests in subsidiaries

 

167

 

63

 

Net income attributable to noncontrolling interests

 

5

 

1

 

Distributions to noncontrolling interests

 

(5

)

 

Other

 

2

 

 

Ending Balance

 

$

232

 

$

64

 

 

LTIP Vesting

 

In May 2010, in connection with the settlement of vested LTIP awards, we issued 283,187 common units at a price of $56.89, for a fair value of approximately $16 million.

 

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PAA Distributions

 

The following table details the distributions pertaining to 2010, 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

 

Incentive

 

2%

 

Total

 

partner unit

 

October 12, 2010

 

November 12, 2010 (1)

 

$

129

 

$

42

 

$

3

 

$

174

 

$

0.9500

 

July 13, 2010

 

August 13, 2010

 

$

129

 

$

40

 

$

3

 

$

172

 

$

0.9425

 

April 13, 2010

 

May 14, 2010

 

$

127

 

$

39

 

$

3

 

$

169

 

$

0.9350

 

January 20, 2010

 

February 12, 2010

 

$

126

 

$

37

 

$

3

 

$

166

 

$

0.9275

 

 


(1)                      Payable to unitholders of record on November 2, 2010, for the period July 1, 2010 through September 30, 2010.

 

Upon closing of the Pacific acquisition in November 2006, the Rainbow acquisition in May 2008 and the PNGS acquisition in September 2009, our general partner agreed to reduce the amounts due it as incentive distributions.  The total reduction in incentive distributions related to these acquisitions is $83 million. Following the distribution in November 2010, the aggregate incentive distribution reductions remaining will be approximately $7 million. See Note 2 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K for further detail regarding our “General Partner Incentive Distributions.”

 

Note 8—Equity Compensation Plans

 

For discussion of our equity compensation awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K.

 

Adoption of PNG Plan

 

During April 2010, PNG’s general partner adopted the PNG Plan.  The majority of the awards granted under the PNG Plan will vest either upon (i) annualized PNG distribution levels of between $1.55 and $1.90 or (ii) upon the conversion of PNG’s Series A or Series B subordinated units.  The PNG Plan limits the number of PNG common units that may be delivered pursuant to awards under the plan to 3,000,000.

 

Class B Units of PNG’s General Partner

 

During July 2010, the Board of Directors of PNG’s general partner authorized the issuance of 165,000 PNG Class B Units.  Approximately 97,625 PNG Class B Units were awarded and the remaining units are reserved for future grants.  The PNG Class B Units earn the right to participate in distributions (i.e. become “earned”) in 25% increments 180 days following annualized PNG distribution levels of $2.00, $2.30, $2.50 and $2.70.  In addition, 50% of the applicable earned units vest immediately upon becoming earned units and the remaining 50% vest on the fifth anniversary of the date of grant. If PNG Class B Units become earned units after the fifth anniversary of the date of grant, 100% of such units will vest immediately upon becoming earned units.  When earned, the PNG Class B Units participate in quarterly distributions paid to PNG’s general partner to the extent such distributions exceed $2.5 million per quarter.  Assuming all 165,000 PNG Class B Units were granted and earned, the maximum participation rate would be 6% of PNG’s quarterly general partner distribution in excess of $2.5 million. As the PNG distribution levels required for vesting are not currently considered to be probable of occurring, no expense was recognized for the PNG Class B Units during the three months ended September 30, 2010.

 

PNG Transaction Grants

 

During September 2010, we entered into agreements with certain of our officers, pursuant to which these officers acquired an aggregate of 375,000 phantom common units, phantom Series A subordinated units, and phantom Series B subordinated units representing a portion of the limited partner interests of PNG issued to us in the IPO. The awards, referred to herein as “PNG Transaction Grants,” will vest upon the completion of the service period and certain performance conditions, including the conversion of PNG’s Series A subordinated units into common units of PNG and the conversion of PNG’s Series B subordinated units into Series A subordinated units of PNG.  Upon vesting, these awards will be settled with outstanding common or Series A subordinated units of PNG currently owned by us, resulting in a dilution of our interest in PNG.

 

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Our equity compensation activity for awards denominated in PAA and PNG units is summarized in the following table (units in millions):

 

 

 

PAA Units (1)

 

PNG Units (2) (3)

 

 

 

 

 

Weighted Average

 

 

 

Weighted Average

 

 

 

 

 

Grant Date

 

 

 

Grant Date

 

 

 

Units

 

Fair Value per Unit

 

Units

 

Fair Value per Unit

 

Outstanding, December 31, 2009

 

3.9

 

$

36.40

 

 

$

 

Granted

 

1.6

 

$

42.45

 

1.1

 

$

20.71

 

Vested

 

(0.7

)

$

34.58

 

 

$

 

Cancelled or forfeited

 

(0.4

)

$

35.66

 

 

$

 

Outstanding, September 30, 2010

 

4.4

 

$

38.93

 

1.1

 

$

20.71

 

 


(1)             Amounts do not include PAA Class B units.

(2)             Amounts do not include PNG Class B units.

(3)             Amounts include PNG Transaction Grants.

 

The table below summarizes the expense recognized and unit or cash settled vestings related to all of our equity compensation plans (in millions):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

Equity compensation expense

 

$

18

 

$

16

 

$

50

 

$

47

 

Unit settled vestings (PAA units only)

 

$

1

 

$

 

$

26

 

$

19

 

Cash settled vestings

 

$

1

 

$

1

 

$

11

 

$

7

 

DER cash payments

 

$

1

 

$

1

 

$

3

 

$

3

 

 

 Note 9—Derivatives and Risk Management Activities

 

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

 

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 (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 positions that are substantially balanced, 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. In connection with our efforts to maintain a balanced position, specifically authorized personnel can 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 continuously 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 supply and logistics 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, 2010, net derivative positions related to these activities included:

 

·      An approximate 207,800 barrels per day net long position (total of 6.2 million barrels) associated with our crude oil activities, which was unwound ratably during October 2010 to match monthly average pricing.

 

·      An approximate 32,400 barrels per day (total of 15.5 million barrels) net short spread position, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2012. These derivatives protect our margin on future floating-price crude oil purchase commitments. These derivatives in the aggregate do not result in exposure to outright price movements.

 

·      A net short spread position averaging approximately 16,000 barrels per day (total of 6.7 million barrels) of calendar spread call options for the period November 2010 through December 2011. These derivatives in the aggregate do not result in exposure to outright price movements.

 

·      Approximately 6,000 barrels per day on average (total of 5.1 million barrels) of WTS/WTI crude oil basis swaps through January 2013, which hedge anticipated sales of crude oil (WTI).

 

Storage Capacity Utilization — We own approximately 63 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 supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk if the market structure is backwardated. As of September 30, 2010, we used derivatives to manage the risk of not utilizing approximately 2.5 million barrels per month of storage capacity through 2012. 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 supply and logistics 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

 

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associated with the inventory. As of September 30, 2010, we had derivatives totaling approximately 17.2 million barrels hedging our inventory.

 

We also purchase foreign cargoes of crude oil and may enter into derivatives to mitigate various price risks associated with the purchase and ultimate sale of foreign crude inventory. As of September 30, 2010, we had approximately 2.1 million barrels of crude oil derivatives hedging the anticipated sale of foreign crude inventory.

 

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, 2010, we had PLA hedges consisting of (i) a net short position consisting of crude oil futures and swaps for an average of approximately 2,100 barrels per day (total of 1.7 million barrels) through December 2012, (ii) a long put option position of approximately 0.3 million barrels through December 2012 and (iii) a long call option position of approximately 1.1 million barrels through December 2011.

 

Natural Gas Purchases and Sales — 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 such anticipated purchases of natural gas. As of September 30, 2010, we have a long position of approximately 1 Bcf consisting of natural gas futures contracts through August 2011 and natural gas call options for approximately 1 Bcf through August 2011.  Additionally, we use derivatives to hedge anticipated sales of operational gas when that gas is no longer needed for cavern development purposes.   As of September 30, 2010, we have a short futures position of approximately 1 Bcf consisting of NYMEX futures.

 

The derivative instruments we use to manage our commodity price risk consist primarily of futures, options and swaps traded on the NYMEX and ICE and in over-the-counter transactions. Over-the-counter transactions include commodity swap and option contracts. 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 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 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 to manage this risk consist primarily of interest rate swaps and treasury locks. As of September 30, 2010, AOCI includes deferred losses of $8 million 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 or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the hedged debt instruments.

 

As of September 30, 2010, we had four outstanding interest rate swaps. For the interest rate swaps, we receive fixed interest payments and pay floating-rate interest payments based on three-month LIBOR plus an average 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.

 

During October 2010, we entered into three forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2013.  The following table summarizes the terms of our forward starting interest rate swaps (notional amounts in millions):

 

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Table of Contents

 

Hedged Transaction

 

Number and Type of
Derivatives Employed

 

Notional
Amount

 

Expected
Termination Date

 

Average Rate
Locked

 

Accounting
Treatment

 

Anticipated debt offering

 

1 forward starting swap (30-year)

 

$

50

 

12/15/2013

 

3.87

%

Cash flow hedge

 

Anticipated debt offering

 

2 forward starting swaps (10-year)

 

$

50

 

10/15/2012

 

3.30

%

Cash flow hedge

 

 

Currency Exchange Rate Risk Hedging

 

We use foreign currency derivatives to hedge foreign currency risk associated with our exposure to fluctuations in the USD-to-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 include foreign currency exchange contracts, forwards and options. As of September 30, 2010, AOCI includes net deferred gains of $16 million 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, 2010, 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 may 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.

 

At September 30, 2010, our open foreign exchange derivatives included forward exchange contracts that exchange CAD for USD on a net basis as follows (in millions):

 

 

 

CAD

 

USD

 

Average Exchange Rate

 

2010

 

$

11

 

$

10

 

CAD $1.15 to USD $1.00

 

2011

 

$

15

 

$

15

 

CAD $1.01 to USD $1.00

 

2012

 

$

15

 

$

15

 

CAD $1.01 to USD $1.00

 

2013

 

$

9

 

$

9

 

CAD $1.00 to USD $1.00

 

 

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

 

Summary of Financial Impact

 

The majority of our derivative activity is related 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 impact earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are 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.

 

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Table of Contents

 

A summary of the impact of our derivative activities recognized in earnings for the three and nine months ended September 30, 2010 and 2009 is as follows (in millions):

 

Three months ended September 30, 2010 and 2009:

 

 

 

Three Months Ended September 30, 2010

 

 

Three Months Ended September 30, 2009

 

 

 

Derivatives in
Cash Flow

 

Derivatives Not

 

 

 

 

Derivatives in
Cash Flow

 

Derivatives Not

 

 

 

 

 

Hedging

 

Designated

 

 

 

 

Hedging

 

Designated

 

 

 

Location of gain/(loss)

 

Relationships (1)

 

as a Hedge (3)

 

Total

 

 

Relationships (1)(2)

 

as a Hedge (3)

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

7

 

$

(32

)

$

(25

)

 

$

(158

)

$

11

 

$

(147

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation segment revenues

 

1

 

 

1

 

 

1

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

11

 

3

 

14

 

 

60

 

4

 

64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

1

 

1

 

 

 

1

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Exchange Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

 

3

 

3

 

 

 

4

 

4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

 

 

 

 

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income, net

 

 

(1

)

(1

)

 

 

(1

)

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Gain/(Loss) on Derivatives Recognized in Income

 

$

19

 

$

(26

)

$

(7

)

 

$

(97

)

$

21

 

$

(76

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

19



Table of Contents

 

Nine months ended September 30, 2010 and 2009:

 

 

 

Nine Months Ended September 30, 2010

 

 

Nine Months Ended September 30, 2009

 

 

 

Derivatives in
Cash Flow

 

Derivatives Not

 

 

 

 

Derivatives in
Cash Flow

 

Derivatives Not

 

 

 

 

 

Hedging

 

Designated

 

 

 

 

Hedging

 

Designated

 

 

 

Location of gain/(loss)

 

Relationships (1)

 

as a Hedge (3)

 

Total

 

 

Relationships (1)(2)

 

as a Hedge (3)

 

Total

 

Commodity Derivatives