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 March 31, 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. 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

 

As of May 3, 2010, there were 136,135,988 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: March 31, 2010 and December 31, 2009

3

Condensed Consolidated Statements of Operations: For the three months ended March 31, 2010 and 2009

4

Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2010 and 2009

5

Condensed Consolidated Statement of Partners’ Capital: For the three months ended March 31, 2010

6

Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2010 and 2009

6

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the three months ended March 31, 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

12

9.

Derivatives and Risk Management Activities

15

10.

Income Taxes

22

11.

Commitments and Contingencies

23

12.

Operating Segments

25

13.

Supplemental Condensed Consolidating Financial Information

26

14.

Subsequent Events

30

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

31

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

42

Item 4. CONTROLS AND PROCEDURES

42

 

 

PART II. OTHER INFORMATION

43

Item 1. LEGAL PROCEEDINGS

43

Item 1A. RISK FACTORS

43

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

43

Item 3. DEFAULTS UPON SENIOR SECURITIES

43

Item 4. [REMOVED AND RESERVED]

43

Item 5. OTHER INFORMATION

43

Item 6. EXHIBITS

43

SIGNATURES

47

 

2



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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)

 

 

 

March 31,

 

December 31,

 

 

 

2010

 

2009

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

16

 

$

25

 

Trade accounts receivable and other receivables, net

 

2,049

 

2,253

 

Inventory

 

1,244

 

1,157

 

Other current assets

 

32

 

223

 

Total current assets

 

3,341

 

3,658

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

7,378

 

7,240

 

Accumulated depreciation

 

(966

)

(900

)

 

 

6,412

 

6,340

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Linefill and base gas

 

521

 

501

 

Long-term inventory

 

123

 

121

 

Goodwill

 

1,297

 

1,287

 

Other, net

 

408

 

451

 

Total assets

 

$

12,102

 

$

12,358

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

2,401

 

$

2,295

 

Short-term debt

 

951

 

1,074

 

Other current liabilities

 

144

 

413

 

Total current liabilities

 

3,496

 

3,782

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Long-term debt under credit facilities and other

 

8

 

6

 

Senior notes, net of unamortized discount of $14 for both periods presented

 

4,136

 

4,136

 

Other long-term liabilities and deferred credits

 

253

 

275

 

Total long-term liabilities

 

4,397

 

4,417

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 11)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (136,135,988 units outstanding for both periods presented)

 

4,051

 

4,002

 

General partner

 

95

 

94

 

Total partners’ capital excluding noncontrolling interest

 

4,146

 

4,096

 

Noncontrolling interest

 

63

 

63

 

Total partners’ capital

 

4,209

 

4,159

 

Total liabilities and partners’ capital

 

$

12,102

 

$

12,358

 

 

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

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2010

 

2009

 

 

 

(unaudited)

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Supply & Logistics segment revenues

 

$

5,912

 

$

3,132

 

Transportation segment revenues

 

138

 

123

 

Facilities segment revenues

 

75

 

47

 

Total revenues

 

6,125

 

3,302

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

Purchases and related costs

 

5,623

 

2,790

 

Field operating costs

 

162

 

152

 

General and administrative expenses

 

62

 

46

 

Depreciation and amortization

 

67

 

58

 

Total costs and expenses

 

5,914

 

3,046

 

 

 

 

 

 

 

OPERATING INCOME

 

211

 

256

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

Equity earnings in unconsolidated entities

 

1

 

3

 

Interest expense (net of capitalized interest of $6 and $3, respectively)

 

(58

)

(51

)

Other income/(expense), net

 

(3

)

4

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

151

 

212

 

Current income tax expense

 

(1

)

(2

)

Deferred income tax benefit

 

1

 

1

 

 

 

 

 

 

 

NET INCOME

 

$

151

 

$

211

 

 

 

 

 

 

 

NET INCOME:

 

 

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

112

 

$

180

 

 

 

 

 

 

 

GENERAL PARTNER

 

$

39

 

$

31

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.80

 

$

1.42

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.80

 

$

1.41

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

136

 

124

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

137

 

125

 

 

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

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2010

 

2009

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

151

 

$

211

 

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

 

 

 

 

 

Depreciation and amortization

 

67

 

58

 

Equity compensation charge

 

19

 

11

 

Deferred gains on settled hedges, net

 

 

9

 

Other

 

(3

)

(4

)

Changes in assets and liabilities, net of acquisitions:

 

 

 

 

 

Trade accounts receivable and other

 

341

 

420

 

Inventory

 

(89

)

121

 

Accounts payable and other current liabilities

 

(95

)

(348

)

Net cash provided by operating activities

 

391

 

478

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Additions to property, equipment and other

 

(104

)

(116

)

Cash received for sale of noncontrolling interest in a subsidiary

 

 

26

 

Other investing activities

 

(4

)

2

 

Net cash used in investing activities

 

(108

)

(88

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net repayments on revolving credit facilities

 

(227

)

(544

)

Net borrowings on short-term letter of credit and hedged inventory facility

 

100

 

78

 

Net proceeds from the issuance of common units

 

 

210

 

Distributions paid to common unitholders (Note 7)

 

(126

)

(110

)

Distributions paid to general partner (Note 7)

 

(40

)

(30

)

Other financing activities

 

1

 

 

Net cash used in financing activities

 

(292

)

(396

)

 

 

 

 

 

 

Effect of translation adjustment on cash

 

 

2

 

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(9

)

(4

)

Cash and cash equivalents, beginning of period

 

25

 

11

 

Cash and cash equivalents, end of period

 

$

16

 

$

7

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

60

 

$

48

 

 

 

 

 

 

 

Cash paid/(refunded) for income taxes, net

 

$

6

 

$

4

 

 

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

 

5



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

 

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

 

 

 

 

Common Units

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Units

 

Amount

 

Partner

 

Interest

 

Interest

 

Capital

 

 

 

(unaudited)

 

Balance, December 31, 2009

 

136

 

$

4,002

 

$

94

 

$

4,096

 

$

63

 

$

4,159

 

Net income

 

 

112

 

39

 

151

 

 

151

 

Distributions (Note 7)

 

 

(126

)

(40

)

(166

)

 

(166

)

Class B Units of Plains AAP, L.P. (Note 8)

 

 

 

1

 

1

 

 

1

 

Equity compensation expense under LTIP (Note 8)

 

 

1

 

 

1

 

 

1

 

Other comprehensive income

 

 

62

 

1

 

63

 

 

63

 

Balance, March 31, 2010

 

136

 

$

4,051

 

$

95

 

$

4,146

 

$

63

 

$

4,209

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2010

 

2009

 

 

 

(unaudited)

 

Net income

 

$

151

 

$

211

 

Other comprehensive income/(loss)

 

63

 

(120

)

Comprehensive income

 

$

214

 

$

91

 

 

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

 

14

 

 

 

14

 

Net deferred loss on cash flow hedges

 

(5

)

 

 

(5

)

Currency translation adjustment

 

 

54

 

 

54

 

Total period activity

 

9

 

54

 

 

63

 

Balance, March 31, 2010

 

$

27

 

$

160

 

$

(1

)

$

186

 

 

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

 

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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 12 for further detail of our operating segments.

 

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

Class B units

= Class B units of Plains AAP, L.P.

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

LPG

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

LTIP

= Long term incentive plan

Mcf

= Thousand cubic feet

MLP

= Master limited partnership

NJDEP

= New Jersey Department of Environmental Protection

NYMEX

= New York Mercantile Exchange

NPNS

= Normal purchase and normal sale

PNG

= PAA Natural Gas Storage, L.P.

PNGS

= PAA Natural Gas Storage, LLC

PAT

= Pacific Atlantic Terminals, LLC

PPS

= Pacific Pipeline System

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

 

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

 

7



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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. 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 months ended March 31, 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

 

Fair Value Measurement Disclosure Requirements.  In January 2010, the FASB issued guidance to improve disclosures relating to fair value measurements. This new guidance requires additional disclosures regarding transfers in and out of Level 1 and Level 2 measurements and requires a gross presentation of activities within the Level 3 roll forward.  This guidance is 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, which is effective for the first interim or annual reporting period beginning after December 15, 2009, on January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations, or cash flows. See Note 9 for applicable disclosure.  We will adopt the guidance that will be effective for annual reporting periods beginning after December 15, 2010 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.

 

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 March 31, 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 $9 million at both March 31, 2010 and December 31, 2009.  Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

At March 31, 2010 and December 31, 2009, we had received approximately $133 million and $212 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties, which cover a significant part of our transactions and also serve to mitigate credit risk.

 

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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):

 

 

 

March 31, 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

 

14,833

 

barrels

 

$

1,156

 

$

77.93

 

12,232

 

barrels

 

$

886

 

$

72.43

 

LPG

 

1,683

 

barrels

 

78

 

$

46.35

 

6,051

 

barrels

 

247

 

$

40.82

 

Refined products

 

127

 

barrels

 

9

 

$

70.87

 

283

 

barrels

 

21

 

$

74.20

 

Natural gas (2)

 

115

 

mcf

 

 

$

2.97

 

181

 

mcf

 

1

 

$

3.30

 

Parts and supplies

 

N/A

 

 

 

1

 

N/A

 

N/A

 

 

 

2

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,244

 

 

 

 

 

 

 

1,157

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,459

 

barrels

 

482

 

$

50.96

 

9,404

 

barrels

 

471

 

$

50.09

 

Natural gas (2)

 

10,994

 

mcf

 

37

 

$

3.37

 

9,194

 

mcf

 

28

 

$

3.04

 

LPG

 

56

 

barrels

 

2

 

$

35.71

 

52

 

barrels

 

2

 

$

38.46

 

Linefill and base gas subtotal

 

 

 

 

 

521

 

 

 

 

 

 

 

501

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,460

 

barrels

 

101

 

$

69.18

 

1,497

 

barrels

 

103

 

$

68.80

 

LPG

 

458

 

barrels

 

22

 

$

48.03

 

458

 

barrels

 

18

 

$

39.30

 

Long-term inventory subtotal

 

 

 

 

 

123

 

 

 

 

 

 

 

121

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

1,888

 

 

 

 

 

 

 

$

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 consists of the following (in millions):

 

 

 

March 31,

 

December 31,

 

 

 

2010

 

2009

 

Short-term debt:

 

 

 

 

 

Senior secured hedged inventory facility bearing interest at a rate of 2.5% and 2.5% as of March 31, 2010 and December 31, 2009, respectively

 

$

400

 

$

300

 

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

 

549

 

772

 

Other

 

2

 

2

 

Total short-term debt

 

951

 

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

 

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

 

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 premium/(discount), net

 

(14

)

(14

)

Long-term debt under credit facilities and other

 

8

 

6

 

Total long-term debt (1) (3)

 

4,144

 

4,142

 

Total debt

 

$

5,095

 

$

5,216

 

 


(1)             We classify 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 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 March 31, 2010, approximately $209 million had been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities.

 

(3)             Our fixed rate senior notes have a face value of approximately $4.2 billion as of March 31, 2010. We estimate the aggregate fair value of these notes as of March 31, 2010 to be approximately $4.5 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.

 

Letters of Credit

 

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters

 

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of credit to secure our obligation for the purchase of crude oil.  At March 31, 2010 and December 31, 2009, we had outstanding letters of credit of approximately $107 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 months ended March 31, 2010 and 2009 (amounts in millions, except per unit data):

 

 

 

Three Months Ended
March 31,

 

 

 

2010

 

2009

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

Net income

 

$

151

 

$

211

 

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

 

(37

)

(28

)

Subtotal

 

114

 

183

 

Less: General partner 2% ownership (1)

 

(2

)

(3

)

Net income available to limited partners

 

112

 

180

 

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

 

(3

)

(4

)

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

 

$

109

 

$

176

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

136

 

124

 

Effect of dilutive securities:

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

137

 

125

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.80

 

$

1.42

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.80

 

$

1.41

 

 


(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 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.

 

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Note 7—Partners’ Capital and Distributions

 

Equity Offerings

 

We did not complete any equity offerings during the three months ended March 31, 2010; however, we completed the following equity offering of our common units during the three months ended March 31, 2009 (in millions, except unit and per unit data):

 

 

 

 

 

 

 

 

 

General

 

 

 

 

 

 

 

 

 

Gross

 

Proceeds

 

Partner

 

 

 

Net

 

Period

 

Units Issued

 

Unit Price

 

from Sale

 

Contribution

 

Costs

 

Proceeds

 

March 2009 (1)

 

5,750,000

 

$

36.90

 

$

212

 

$

4

 

$

(6

)

$

210

 

 


(1)             This offering of common units was an underwritten transaction that required us to pay a gross spread. The net proceeds from this offering were used to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

 

Distributions

 

The following table details the distributions pertaining to the first three months of 2010 and 2009, 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

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

April 13, 2010

 

May 14, 2010 (1)

 

$

127

 

$

39

 

$

3

 

$

169

 

$

0.9350

 

January 20, 2010

 

February 12, 2010

 

$

126

 

$

37

 

$

3

 

$

166

 

$

0.9275

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

April 8, 2009

 

May 15, 2009

 

$

117

 

$

32

 

$

2

 

$

151

 

$

0.9050

 

January 14, 2009

 

February 13, 2009

 

$

110

 

$

28

 

$

2

 

$

140

 

$

0.8925

 

 


(1)             Payable to unitholders of record on May 4, 2010, for the period January 1, 2010 through March 31, 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 May 2010, the aggregate incentive distribution reductions remaining will be approximately $14 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

 

LTIPs

 

For discussion of our LTIP awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K.  At March 31, 2010, the following LTIP awards were outstanding (units in millions):

 

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Vesting

 

 

 

 

 

 

 

 

 

 

 

 

 

LTIP Units

 

Distribution

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding

 

Amount

 

2010

 

2011

 

2012

 

2013

 

2014

 

2015

 

0.6

(1)

$3.20

 

0.6

 

 

 

 

 

 

3.0

(2)

$3.50 - $4.50

 

 

0.5

 

0.9

 

0.6

 

0.5

 

0.5

 

1.7

(3)

$3.50 - $4.25

 

0.5

 

0.3

 

0.7

 

0.2

 

 

 

5.3

(4) (5)  

 

 

1.1

 

0.8

 

1.6

 

0.8

 

0.5

 

0.5

 

 


(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 continue to be employed for the requisite service period, these awards will be forfeited. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

 

(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, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

 

(4)             Approximately 3 million of our approximately 5.3 million outstanding LTIP awards also include DERs, of which approximately 1 million are currently earned.

 

(5)             LTIP units outstanding do not include Class B units 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, 2009

 

3.9

 

$

36.40

 

Granted (1)

 

1.5

 

$

42.53

 

Vested

 

 

$

 

Cancelled or forfeited

 

(0.1

)

$

31.54

 

Outstanding, March 31, 2010

 

5.3

 

$

38.18

 

 


(1)             Includes approximately 1 million equity classified awards.

 

Our accrued liability at March 31, 2010 related to all outstanding liability classified LTIP awards and DERs is approximately $104 million, which includes an accrual associated with our assessment that an annualized distribution of $3.90 is probable of occurring. We have not deemed a distribution of more than $3.90 to be probable. At December 31, 2009, the accrued liability was approximately $87 million.

 

Class B Units

 

For further discussion of the Class B units, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2009 Annual Report on Form 10-K. The following table contains a summary of Class B unit awards that were (i) reserved for future

 

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grants (ii) outstanding and (iii) earned as of and for the three months ended March 31, 2010 and as of December 31, 2009:

 

 

 

Reserved for
Future Grants

 

Outstanding

 

Outstanding Units
Earned

 

 

Grant Date
Fair Value Of
Outstanding Class B
Units 
(1)

 

 

 

 

 

 

 

 

 

 

(in millions)

 

Balance, December 31, 2009

 

34,500

 

165,500

 

38,500

 

 

$

36

 

Class B unit issuance

 

(3,000

)

3,000

 

 

 

 

Class B units earned

 

 

 

 

 

 

Balance, March 31, 2010

 

31,500

 

168,500

 

38,500

 

 

$

36

 

 


(1)         Of the grant date fair value, approximately $1 million was recognized as expense during the three months ended March 31, 2010.

 

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 vesting (settled both in units and cash) related to our equity compensation plans (in millions):

 

 

 

Three Months Ended

 

Three Months Ended

 

 

 

March 31,

 

March 31,

 

 

 

2010

 

2009

 

 

 

Liability Awards

 

Equity Awards

 

Liability Awards

 

Equity Awards

 

Equity compensation expense

 

$

17

 

$

2

 

$

10

 

$

1

 

LTIP unit vestings

 

$

 

$

 

$

 

$

 

LTIP cash settled vestings

 

$

 

$

 

$

 

$

 

DER cash payments

 

$

1

 

$

 

$

1

 

$

 

 

Based on the March 31, 2010 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $68 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. For our liability classified awards, this estimate is based on the closing market price of our units of $56.90 at March 31, 2010. For our equity classified awards, this estimate is based on the closing price of our units as of the grant date. 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

 

 

 

Plans Remaining Fair Value

 

Year

 

Amortization (1) (2)

 

2010 (3)

 

$

28

 

2011

 

22

 

2012

 

14

 

2013

 

4

 

Total

 

$

68

 

 


(1)             Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at March 31, 2010.

 

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(2)             Includes unamortized fair value associated with Class B units.

 

(3)             Includes equity compensation plan fair value amortization for the remaining nine months of 2010.

 

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.  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 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 (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 supply and logistics 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, 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 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 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 March 31, 2010, material net derivative positions related to these activities included:

 

·                  An approximate 222,000 barrels per day net long position (total of 6.7 million barrels) associated with our crude oil activities, which was unwound ratably during April 2010 to match monthly average pricing.

 

·                  An approximate 29,900 barrels per day (total of 19.8 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 3,400 barrels per day (total of 2.1 million barrels) of calendar spread call options for the period April 2010 through January 2012. These derivatives in the aggregate do not result in exposure to outright price movements.

 

·                  An average of approximately 3,000 barrels per day (total of 1.1 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 March 2011.

 

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·                  Approximately 18,400 barrels per day on average (total of 5.0 million barrels) of crude oil basis differential hedges through December 2010.

 

Storage Capacity Utilization — We own approximately 59 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 March 31, 2010, we used derivatives to manage the risk of not utilizing approximately 2.6 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 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 associated with the inventory.  As of March 31, 2010, we had approximately 8.9 million barrels of inventory hedged with derivatives.

 

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 March 31, 2010, we had approximately 1.5 million barrels of crude oil derivatives hedging the anticipated sale of foreign crude inventory and 2.9 million barrels of crude oil spread positions hedging the anticipated purchase 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 March 31, 2010, 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 2.3 million barrels) from  April 2010 through December 2012.  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 1.5 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 March 31, 2010, we had an average of 1,300 barrels per day of natural gasoline/WTI spread positions (approximately 1 million barrels) that run through mid-2011 and an average of 3,300 barrels per day of short crude oil futures (approximately 0.3 million barrels) to hedge condensate through the second 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 such anticipated purchases of natural gas.  As of March 31, 2010, we have a net long position of approximately 2 Bcf consisting of natural gas futures contracts through August 2011 and natural gas call options for approximately 1 Bcf through August 2011.

 

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 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 to manage this risk consist primarily of interest rate swaps and

 

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treasury locks.  As of March 31, 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 and refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the forecasted debt instruments.

 

As of March 31, 2010, 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 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.

 

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 primarily include foreign currency exchange contracts, forwards and options.  As of March 31, 2010, AOCI includes net deferred gains of $15 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 March 31, 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 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 March 31, 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

 

$

32

 

$

29

 

CAD $1.14 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 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 months ended March 31, 2010 is as follows (in millions):

 

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Three Months Ended March 31, 2010:

 

 

 

 

 

Derivatives in Cash Flow

 

 

 

 

 

 

 

 

 

Hedging Relationships

 

Derivatives Not

 

 

 

 

 

 

 

AOCI

 

Ineffective

 

Designated

 

 

 

 

 

Location of gain/(loss)

 

Reclass (1)

 

Portion (2)

 

as a Hedge (3)

 

Total

 

Commodity derivatives

 

Supply and Logistics segment revenues

 

$

(19

)

$

(1

)

$

27

 

$

7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation segment revenues

 

1

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

(1

)

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

5

 

 

(24

)

(19

)

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate derivatives

 

Other income, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense

 

 

 

1

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange derivatives

 

Supply and Logistics segment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

 

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income, net

 

 

 

(1

)

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

Total Gain/(Loss) on Derivatives Recognized in Income

 

$

(14

)

$

(1

)

$

6

 

$

(9

)

 


(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 were recognized in earnings during the period.

 

(3)      Includes realized and  unrealized gains or losses for derivatives not designated for hedge accounting during the period.

 

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Table of Contents

 

A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2009 is as follows (in millions):

 

Three Months Ended March 31, 2009:

 

 

 

 

 

Derivatives in Cash Flow

 

 

 

 

 

 

 

 

 

Hedging Relationships

 

Derivatives Not

 

 

 

 

 

 

 

AOCI

 

Ineffective

 

Designated

 

 

 

 

 

Location of gain/(loss)

 

Reclass (1)

 

Portion (2)

 

as a Hedge (3)

 

Total

 

Commodity derivatives

 

Supply and Logistics segment revenues

 

$

125

 

$

(1

)

$

(29

)

$

95

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation segment revenues

 

2

 

 

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

(32

)

 

95

 

63

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate derivatives

 

Other income, net

 

 

 

(1

)

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange derivatives

 

Supply and Logistics segment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

 

 

(5

)

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income, net

 

5

 

 

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Gain/(Loss) on Derivatives Recognized in Income

 

$

100

 

$

(1

)

$

60

 

$

159

 

 


(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 were recognized in earnings during the period.

 

(3)      Includes realized and  unrealized gains or losses for derivatives not designated for hedge accounting during the period.

 

19



Table of Contents

 

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of March 31, 2010 (in millions):

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

Balance Sheet

Location

 

Fair Value

 

 

Balance Sheet

Location

 

Fair Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

52

 

 

Other current assets

 

$

(50

)

 

 

Other long-term assets

 

27

 

 

Other current liabilities

 

(11

)

 

 

Other long-term liabilities

 

6

 

 

Other long-term liabilities

 

(1

)

Foreign exchange derivatives

 

Other long-term assets

 

1

 

 

Other long-term liabilities

 

 

Total derivatives designated as hedging instruments

 

 

 

$

86

 

 

 

 

$

(62

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

77

 

 

Other current assets

 

$

(82

)

 

 

Other long-term assets

 

29

 

 

Other current liabilities

 

 

 

 

Other long-term liabilities

 

6

 

 

Other long-term liabilities

 

(11

)

Interest rate derivatives

 

Other current assets

 

3

 

 

Other current liabilities

 

 

Foreign exchange derivatives

 

Other current assets

 

1

 

 

Other current liabilities

 

(3

)

Total derivatives not designated as hedging instruments

 

 

 

$

116

 

 

 

 

$

(96

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

202

 

 

 

 

$

(158

)

 

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of December 31, 2009 (in millions):

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

Balance Sheet

 

 

 

 

Balance Sheet

 

 

 

 

 

Location

 

Fair Value

 

 

Location

 

Fair Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

153

 

 

Other current liabilities

 

$

(140

)

 

 

Other long-term assets

 

34

 

 

Other long-term liabilities

 

(1

)

Foreign exchange derivatives

 

Other long-term assets