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 June 30, 2009

 

OR

 

o

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

 

Commission file number: 1-14569

 

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

76-0582150

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

 

 

333 Clay Street, Suite 1600, Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

(713) 646-4100

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. xYes  oNo

 

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

 

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

 

Large accelerated filer  x

 

Accelerated filer  o

 

Non-accelerated filer  o

 

Smaller reporting company  o

 

 

 

 

(Do not check if a smaller
reporting company)

 

 

 

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

 

At August 4, 2009, there were outstanding 128,938,683 Common Units.

 

 

 



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

 

TABLE OF CONTENTS

 

 

Page

PART I. FINANCIAL INFORMATION

3

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

3

Condensed Consolidated Balance Sheets: June 30, 2009 and December 31, 2008

3

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

4

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

5

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

6

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

6

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

6

Notes to the Condensed Consolidated Financial Statements

7

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

27

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

38

Item 4. CONTROLS AND PROCEDURES

38

PART II. OTHER INFORMATION

39

Item 1. LEGAL PROCEEDINGS

39

Item 1A. RISK FACTORS

39

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

39

Item 3. DEFAULTS UPON SENIOR SECURITIES

39

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

39

Item 5. OTHER INFORMATION

39

Item 6. EXHIBITS

40

SIGNATURES

43

 

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)

 

 

 

June 30,

 

December 31,

 

 

 

2009

 

2008

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

7

 

$

11

 

Trade accounts receivable and other receivables, net

 

1,674

 

1,525

 

Inventory

 

995

 

801

 

Other current assets

 

246

 

259

 

Total current assets

 

2,922

 

2,596

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

6,028

 

5,727

 

Accumulated depreciation

 

(773

)

(668

)

 

 

5,255

 

5,059

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Pipeline linefill in owned assets

 

429

 

425

 

Long-term inventory

 

127

 

139

 

Investment in unconsolidated entities

 

256

 

257

 

Goodwill

 

1,226

 

1,210

 

Other, net

 

344

 

346

 

Total assets

 

$

10,559

 

$

10,032

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

1,927

 

$

1,507

 

Short-term debt

 

938

 

1,027

 

Other current liabilities

 

343

 

426

 

Total current liabilities

 

3,208

 

2,960

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Long-term debt under credit facilities and other

 

4

 

40

 

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

 

3,394

 

3,219

 

Other long-term liabilities and deferred credits

 

247

 

261

 

Total long-term liabilities

 

3,645

 

3,520

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 11)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (128,938,683 and 122,911,645 units outstanding, respectively)

 

3,558

 

3,469

 

General partner

 

85

 

83

 

Total partners’ capital excluding noncontrolling interest

 

3,643

 

3,552

 

Noncontrolling interest

 

63

 

 

Total partners’ capital

 

3,706

 

3,552

 

Total liabilities and partners’ capital

 

$

10,559

 

$

10,032

 

 

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

 

3



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

 

 

(unaudited)

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

Crude oil, refined products and LPG sales and related revenues

 

$

4,099

 

$

8,880

 

$

7,231

 

$

15,917

 

Pipeline tariff activities, trucking and related revenues

 

130

 

144

 

254

 

268

 

Storage, terminalling, processing and related revenues

 

53

 

36

 

100

 

70

 

Total revenues

 

4,282

 

9,060

 

7,585

 

16,255

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Crude oil, refined products and LPG purchases and related costs

 

3,829

 

8,724

 

6,619

 

15,560

 

Field operating costs

 

160

 

152

 

312

 

297

 

General and administrative expenses

 

54

 

51

 

100

 

90

 

Depreciation and amortization

 

56

 

52

 

114

 

100

 

Total costs and expenses

 

4,099

 

8,979

 

7,145

 

16,047

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

183

 

81

 

440

 

208

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

5

 

4

 

8

 

7

 

Interest expense (net of capitalized interest of $2, $3, $5 and $9, respectively)

 

(56

)

(49

)

(107

)

(91

)

Interest income and other income/(expense), net

 

2

 

10

 

5

 

12

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

134

 

46

 

346

 

136

 

Current income tax expense

 

 

(5

)

(2

)

(6

)

Deferred income tax benefit

 

2

 

 

3

 

3

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

$

136

 

$

41

 

$

347

 

$

133

 

 

 

 

 

 

 

 

 

 

 

NET INCOME-LIMITED PARTNERS

 

$

102

 

$

16

 

$

282

 

$

83

 

 

 

 

 

 

 

 

 

 

 

NET INCOME-GENERAL PARTNER

 

$

34

 

$

25

 

$

65

 

$

50

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.79

 

$

0.09

 

$

2.20

 

$

0.65

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.78

 

$

0.09

 

$

2.18

 

$

0.64

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

129

 

120

 

126

 

118

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

130

 

121

 

127

 

119

 

 

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

 

4



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Six Months Ended June 30,

 

 

 

2009

 

2008

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

347

 

$

133

 

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

 

 

 

 

 

Depreciation and amortization

 

114

 

100

 

Equity compensation charge

 

30

 

24

 

Other

 

(1

)

(13

)

Changes in assets and liabilities, net of acquisitions:

 

 

 

 

 

Trade accounts receivable and other

 

(162

)

(559

)

Inventory

 

(178

)

(234

)

Accounts payable and other liabilities

 

137

 

1,125

 

Net cash provided by operating activities

 

287

 

576

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions

 

(56

)

(661

)

Additions to property, equipment and other

 

(228

)

(301

)

Investment in unconsolidated entities

 

(5

)

(40

)

Cash received for sale of noncontrolling interest in a subsidiary

 

26

 

 

Proceeds from the sale of assets and other

 

10

 

15

 

Net cash used in investing activities

 

(253

)

(987

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net borrowings/(repayments) on revolving credit facility

 

(459

)

(204

)

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

 

157

 

(56

)

Net proceeds from the issuance of senior notes (Note 5)

 

350

 

597

 

Net proceeds from the issuance of common units

 

210

 

315

 

Distributions paid to common unitholders (Note 7)

 

(227

)

(199

)

Distributions paid to general partner (Note 7)

 

(64

)

(52

)

Other financing activities

 

(5

)

(5

)

Net cash provided by (used in) financing activities

 

(38

)

396

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

 

2

 

Net decrease in cash and cash equivalents

 

(4

)

(13

)

Cash and cash equivalents, beginning of period

 

11

 

24

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

7

 

$

11

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

103

 

$

92

 

 

 

 

 

 

 

Cash paid for income taxes

 

$

7

 

$

4

 

 

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

 

5



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

 

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

 

 

 

 

Common Units

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Units

 

Amount

 

Partner

 

Interest

 

Interest

 

Capital

 

 

 

(unaudited)

 

Balance, December 31, 2008

 

123

 

$

3,469

 

$

83

 

$

3,552

 

$

 

$

3,552

 

Sale of noncontrolling interest in a subsidiary

 

 

(36

)

(1

)

(37

)

63

 

26

 

Net income

 

 

282

 

65

 

347

 

 

347

 

Issuance of common units

 

6

 

206

 

4

 

210

 

 

210

 

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

 

 

12

 

 

12

 

 

12

 

Distributions

 

 

(227

)

(64

)

(291

)

 

(291

)

Class B Units of Plains AAP, L.P.

 

 

2

 

 

2

 

 

2

 

Other comprehensive loss

 

 

(150

)

(2

)

(152

)

 

(152

)

Balance, June 30, 2009

 

129

 

$

3,558

 

$

85

 

$

3,643

 

$

63

 

$

3,706

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

136

 

$

41

 

$

347

 

$

133

 

Other comprehensive income/(loss)

 

(32

)

20

 

(152

)

(45

)

Comprehensive income

 

$

104

 

$

61

 

$

195

 

$

88

 

 

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

 

 

Cash Flow

 

Translation

 

 

 

 

 

 

 

Hedging Activities

 

Adjustments

 

Other

 

Total

 

 

 

(unaudited)

 

Balance, December 31, 2008

 

$

161

 

$

(86

)

$

 

$

75

 

 

 

 

 

 

 

 

 

 

 

Reclassification adjustments

 

(118

)

 

 

(118

)

Changes in fair value of outstanding hedge positions

 

(38

)

 

 

(38

)

Deferred losses on settled hedges, net

 

(47

)

 

 

(47

)

Currency translation adjustment

 

 

59

 

 

59

 

Proportionate share of our unconsolidated entities’ other comprehensive loss

 

 

 

(8

)

(8

)

Total period activity

 

(203

)

59

 

(8

)

(152

)

 

 

 

 

 

 

 

 

 

 

Balance, June 30, 2009

 

$

(42

)

$

(27

)

$

(8

)

$

(77

)

 

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

 

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

 

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2008 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated.  The condensed balance sheet data as of December 31, 2008 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.  The results of operations for the three and six months ended June 30, 2009 should not be taken as indicative of the results to be expected for the full year.

 

Subsequent events have been evaluated through the financial statements issuance date of August 7, 2009 and have been included within the following footnotes where applicable.

 

Note 2—Recent Accounting Pronouncements

 

Standards Adopted as of April 1, 2009

 

In May 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 165, “Subsequent Events” (“SFAS 165”).  SFAS 165 establishes general standards of accounting for and disclosure of subsequent events or events that occur after the balance sheet date but before financial statements are issued.  This standard sets forth (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date.  This standard was effective for interim or annual periods ending after June 15, 2009; therefore, we have adopted SFAS 165 as of April 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

In April 2009, the FASB issued FASB Staff Position (“FSP”) No. FAS 107-1, “Interim Disclosures about Fair Value of Financial Statements” (“FSP No. FAS 107-1”).  FSP No. FAS 107-1 increases the frequency of fair value disclosures from annual to quarterly in an effort to provide financial statement users with more timely and transparent information about the effects of current market conditions on financial instruments. This is intended to address concerns raised by some financial statement users about the lack of comparability resulting from the use of different measurement attributes for financial instruments. These disclosures are also intended to stimulate more robust discussions about financial instrument valuations between users and reporting entities. We have adopted FSP No. FAS 107-1 as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

Standards Adopted as of January 1, 2009

 

In November 2008, the Emerging Issues Task Force (“EITF”) issued Issue No. 08-06, “Equity Method Investment Accounting Considerations” (“EITF 08-06”). EITF 08-06 addresses certain accounting considerations, including initial measurement, decreases in investment value, and changes in the level of ownership or degree of influence related to equity method investments. We have adopted EITF 08-06 as of January 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other generally accepted accounting principles. We have adopted FSP No. FAS 142-3 as of January 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

 

In March 2008, the EITF issued Issue No. 07-04, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-04”). EITF 07-04 addresses the application of the two-class method under SFAS No. 128, “Earnings

 

7



Table of Contents

 

Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. The two-class method is an earnings allocation formula that determines earnings per unit for each class of common units and participating securities according to participation rights in undistributed earnings. We have adopted EITF 07-04 as of January 1, 2009.  The guidance in this Issue has been applied retrospectively for all financial statement periods presented.  Adoption impacted the net income available to limited partners used in our computation of earnings per unit, but did not impact our net income, distributions to limited partners, financial position, results of operations or cash flows.  See Note 6 for additional disclosure.

 

Note 3—Trade Accounts Receivable

 

At June 30, 2009 and December 31, 2008, we had received approximately $147 million and $66 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit risk.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.  At June 30, 2009 and December 31, 2008, substantially all of our net accounts receivable classified as current assets were less than 30 days past their scheduled invoice date.  Our allowance for doubtful accounts receivable totaled $8 million and $5 million at June 30, 2009 and December 31, 2008, respectively.  Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

Note 4—Inventory, Linefill and Long-term Inventory

 

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

 

 

 

June 30, 2009

 

December 31, 2008

 

 

 

 

 

 

 

Dollars/

 

 

 

 

 

Dollars/

 

 

 

Barrels

 

Dollars

 

Barrel (1)

 

Barrels

 

Dollars

 

Barrel (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

13,694

 

$

774

 

$

56.52

 

9,986

 

$

421

 

$

42.16

 

LPG

 

5,882

 

216

 

$

36.72

 

7,748

 

370

 

$

47.75

 

Refined products

 

40

 

2

 

$

50.00

 

103

 

5

 

$

48.54

 

Parts and supplies

 

N/A

 

3

 

N/A

 

N/A

 

5

 

N/A

 

Inventory subtotal

 

19,616

 

995

 

 

 

17,837

 

801

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline linefill in owned assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,101

 

427

 

$

46.92

 

9,148

 

422

 

$

46.13

 

LPG

 

51

 

2

 

$

39.22

 

67

 

3

 

$

44.78

 

Pipeline linefill in owned assets subtotal

 

9,152

 

429

 

 

 

9,215

 

425

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,690

 

115

 

$

68.05

 

1,781

 

121

 

$

67.94

 

LPG

 

342

 

12

 

$

35.09

 

363

 

18

 

$

49.59

 

Long-term inventory subtotal

 

2,032

 

127

 

 

 

2,144

 

139

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

30,800

 

$

1,551

 

 

 

29,196

 

$

1,365

 

 

 

 


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

 

Note 5—Debt

 

Debt consists of the following (in millions):

 

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June 30,

 

December 31,

 

 

 

2009

 

2008

 

Short-term debt:

 

 

 

 

 

Senior secured hedged inventory facility bearing interest at a rate of 2.1% and 2.3% at June 30, 2009 and December 31, 2008, respectively

 

$

436

 

$

280

 

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

 

325

 

746

 

Senior notes, net of unamortized discount (2) (3)

 

175

 

 

Other

 

2

 

1

 

Total short-term debt

 

938

 

1,027

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

Long-term debt under senior unsecured revolving credit facility and other (1)

 

4

 

40

 

Senior notes, net of unamortized net premium and discount

 

3,394

 

3,219

 

Total long-term debt (1) (3)

 

3,398

 

3,259

 

 

 

 

 

 

 

Total debt

 

$

4,336

 

$

4,286

 

 


(1)          At June 30, 2009 and December 31, 2008, we have classified $325 million and $746 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”) margin deposits.

 

(2)          Our $175 million 4.75% senior notes will mature on August 15, 2009 (see discussion of the issuance of our $350 million 8.75% senior notes below).

 

(3)          We estimate the aggregate fair value of our fixed-rate senior notes at June 30, 2009 to be approximately $3,550 million.  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.

 

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

 

In April 2009, we completed the issuance of $350 million of 8.75% Senior Notes due May 1, 2019.  The senior notes were sold at 99.994% of face value.  Interest payments are due on May 1 and November 1 of each year, beginning on November 1, 2009.  We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities, which may be reborrowed to fund future investments and for general partnership purposes, including repayment of our $175 million 4.75% senior notes that mature in August 2009.

 

Letters of Credit

 

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

 

Note 6—Net Income per Limited Partner Unit

 

Basic and diluted net income per unit is determined by dividing our limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period.  Pursuant to EITF 07-04, the limited partners’ interest in net income is calculated by first reducing net income by the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter (including the incentive distribution interest in excess of the 2% general partner interest).  Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.  The adoption of EITF 07-04 resulted in a change to our calculation of earnings per unit by using distributions applicable to the period rather than distributions paid in the period (applicable to

 

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the previous period).  Also, in accordance with EITF 07-04, earnings per unit for prior periods were recast to conform to this revised calculation.

 

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the six months ended  June 30, 2009 and 2008 (amounts in millions, except per unit data):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

Net income

 

$

136

 

$

41

 

$

347

 

$

133

 

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

 

(32

)

(25

)

(60

)

(49

)

Subtotal

 

104

 

16

 

287

 

84

 

Less: General partner 2% ownership (1)

 

(2

)

 

(5

)

(1

)

Net income available to limited partners

 

102

 

16

 

282

 

83

 

Adjustment in accordance with EITF 07-04 (1)

 

 

(5

)

(5

)

(7

)

Net income available to limited partners in accordance with EITF 07-04

 

$

102

 

$

11

 

$

277

 

$

76

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

129

 

120

 

126

 

118

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

130

 

121

 

127

 

119

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.79

 

$

0.09

 

$

2.20

 

$

0.65

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.78

 

$

0.09

 

$

2.18

 

$

0.64

 

 


(1)         We allocate net income to our general partner based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest).  EITF 07-04 requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized within the earnings per unit calculation.  We reflect the impact of this difference as the “Adjustment in accordance with EITF 07-04.”

 

(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 SFAS No. 128, “Earnings per Share.

 

Note 7—Partners’ Capital and Distributions

 

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Equity Offerings

 

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

 

 

 

 

 

 

 

 

 

General

 

 

 

 

 

 

 

 

 

Gross

 

Proceeds

 

Partner

 

 

 

Net

 

Period

 

Units Issued

 

Unit Price

 

from Sale

 

Contribution

 

Costs (1)

 

Proceeds

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

March 2009

 

5,750,000

 

$

36.90

 

$

212

 

$

4

 

$

(6

)

$

210

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

April 2008

 

6,900,000

 

$

46.31

 

$

320

 

$

6

 

$

(11

)

$

315

 

 


(1)  Costs include the gross spread paid to underwriters in connection with the March 2009 and April 2008 equity offerings of common units.

 

LTIP Vesting

 

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

 

Distributions

 

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

 

 

 

 

 

Distributions Paid

 

Distributions

 

 

 

 

 

Common

 

General Partner

 

 

 

per limited

 

Date Declared

 

Date Paid or To Be Paid

 

Units

 

Incentive

 

2%

 

Total

 

partner unit

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

July 15, 2009

 

August 14, 2009 (1)

 

$

117

 

$

32

 

$

2

 

$

151

 

$

0.9050

 

April 8, 2009

 

May 15, 2009

 

$

117

 

$

32

 

$

2

 

$

151

 

$

0.9050

 

January 14, 2009

 

February 13, 2009

 

$

110

 

$

28

 

$

2

 

$

140

 

$

0.8925

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

July 14, 2008

 

August 14, 2008

 

$

109

 

$

30

 

$

2

 

$

141

 

$

0.8875

 

April 17, 2008

 

May 15, 2008

 

$

100

 

$

25

 

$

2

 

$

127

 

$

0.8650

 

January 16, 2008

 

February 14, 2008

 

$

99

 

$

23

 

$

2

 

$

124

 

$

0.8500

 

 


(1)                Payable to unitholders of record on August 4, 2009, for the period April 1, 2009 through June 30, 2009.

 

Upon closing of the Pacific and Rainbow acquisitions, our general partner agreed to reduce the amounts due it as incentive distributions. The total reduction in incentive distributions related to these acquisitions is $75 million. Following the distribution in August 2009, the aggregate remaining incentive distribution reductions related to these acquisitions will be approximately $21 million.

 

Note 8—Equity Compensation Plans

 

Long-Term Incentive Plans

 

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

 

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Vesting

 

 

 

 

 

 

 

 

 

 

 

LTIP Units

 

Distribution

 

Estimated Unit Vesting Date

 

Outstanding

 

Amount

 

2009

 

2010

 

2011

 

2012

 

2013

 

0.6

(1)

$3.20

 

 

0.6

 

 

 

 

1.4

(2)

$3.50 - $4.50

 

 

 

0.8

 

0.5

 

0.1

 

1.5

(3)

$3.50 - $4.00

 

 

0.9

 

0.2

 

0.4

 

 

3.5

(4) (5)

 

 

 

1.5

 

1.0

 

0.9

 

0.1

 

 


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

 

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

 

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

 

(4)             Approximately 1.7 million of our approximately 3.5 million outstanding LTIP awards also include Distribution Equivalent Rights (“DERs”), of which 1 million are currently earned.

 

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

 

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

 

 

 

 

 

Weighted Average

 

 

 

 

 

Grant Date

 

 

 

Units

 

Fair Value per Unit

 

Outstanding, December 31, 2008

 

3.9

 

$

36.44

 

Granted

 

0.3

 

$

26.56

 

Vested

 

(0.6

)

$

34.72

 

Cancelled or forfeited

 

(0.1

)

$

38.99

 

Outstanding, June 30, 2009

 

3.5

 

$

36.68

 

 

Our accrued liability at June 30, 2009 related to all outstanding LTIP awards and DERs is approximately $55 million, which includes an accrual associated with our assessment that an annualized distribution of $3.75 is probable of occurring. We have not deemed a distribution of more than $3.75 to be probable. At December 31, 2008, the accrued liability was approximately $55 million.

 

Class B Units of Plains AAP, L.P.

 

At June 30, 2009, 165,500 Class B units were outstanding, of which 38,500 units were earned. A total of 34,500 units were reserved for future grants. During the six months ended June 30, 2009, 11,500 Class B units were issued to certain members of our senior management. These Class B units become earned in increments of 37.5%, 37.5% and 25% 180 days after us achieving annualized distribution levels of $3.75, $4.00 and $4.50, respectively.  The total grant date fair value of the 165,500 Class B units outstanding at June 30, 2009 was approximately $35 million of which approximately $1 million and $2 million was recognized as expense during the three months and six months ended June 30, 2009, respectively. For further discussion of the Class B units, see Note 10 to our Consolidated Financial Statements included in our 2008 Annual Report on Form 10-K.

 

Other Consolidated Equity Compensation Information

 

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

 

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Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

Equity compensation expense

 

$

19

 

$

18

 

$

30

 

$

24

 

LTIP unit settled vestings

 

$

18

 

$

1

 

$

18

 

$

1

 

LTIP cash settled vestings

 

$

7

 

$

1

 

$

7

 

$

2

 

DER cash payments

 

$

1

 

$

1

 

$

2

 

$

2

 

 

Based on the June 30, 2009 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $44 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. This estimate is based on the closing market price of our units of $42.55 at June 30, 2009. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessment regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

 

 

 

Equity Compensation

 

 

 

Plan Fair Value

 

Year

 

Amortization (1) (2)

 

2009 (3)

 

$

13

 

2010

 

20

 

2011

 

8

 

2012

 

3

 

Total

 

$

44

 

 


(1)             Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at June 30, 2009.

 

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

 

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

 

Note 9—Derivatives and Risk Management Activities

 

We identify the risks that underlie our core business activities and utilize risk management activities 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. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.  A discussion of our derivative activities by risk category follows.

 

Commodity Price Risk Hedging

 

Our core business activities contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments.  Our policy is generally (i) to purchase only product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect the segment profit we earn, and (iii) not to acquire and hold physical inventory, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.  Although we seek to maintain a position that is substantially balanced within our marketing activities, we purchase crude oil 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

 

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uncontrollable events that occur within each month. In connection with our efforts to maintain a balanced position, our personnel are authorized to purchase or sell an aggregate limit of up to 810,000 barrels of crude oil, refined products and LPG relative to the volumes originally scheduled for such month, based on interim information.  The purpose of these purchases and sales is to manage risk as opposed to establishing a risk position. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time.

 

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

 

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

 

·                  An approximate 187,000 barrel per day net long position (total net of 5.6 million barrels) associated with our crude oil activities, which was unwound ratably during July 2009 to match monthly average pricing.

 

·                  A net short position averaging approximately 15,900 barrels per day (total of 8.1 million barrels) of calendar spread call options for the period August 2009 through December 2010.  These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

 

·                  An average of approximately 3,500 barrels per day (total of 1.9 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are priced as a fixed percentage of WTI and continue through 2010.

 

·                  Approximately 16,100 barrels per day on average (total of 8.7 million barrels) of crude oil basis differential hedges, which run through 2010.

 

Storage Capacity Utilization — We own approximately 56 million barrels of crude oil, LPG and refined products storage capacity that is not used in our transportation operations.  This storage may be leased to third parties or utilized in our own marketing activities, including for the storage of inventory in a contango market. For capacity allocated to our marketing operations we have utilization risk if the market structure is backwardated. As of June 30, 2009, we used derivatives to manage the risk of not utilizing approximately 3 million barrels per month of storage capacity through 2011.  These positions are a combination of calendar spread options and NYMEX futures contracts.    These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

 

Inventory Storage — At times, we elect to purchase and store crude oil, LPG and refined products inventory in conjunction with our marketing activities.  These activities primarily relate to the seasonal storage of LPG inventories and contango market storage activities.  When we purchase and store barrels, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory.  As of June 30, 2009, we had approximately 10 million barrels of inventory hedged with derivatives.

 

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

 

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit.  We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs.  As of June 30, 2009, we had entered into a net short position consisting of crude oil futures and swaps to manage the risk associated with the anticipated sale of an average of approximately 2,300 barrels per day (total of 2.1 million barrels) from July 2009 through December 2011.  In addition, we had a long put option position of approximately 1 million barrels through December 2012 and a net long call option position of approximately 2 million barrels through December 2011, which provide upside price participation.

 

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Diluent Purchases — We use diluent in our Canadian crude oil operations and have used derivative instruments to hedge the anticipated forward purchases of diluent.  As of June 30, 2009, we had an average of 4,900 barrels per day of natural gasoline/WTI spread positions (approximately 3.5 million barrels) that run through mid-2011.

 

The derivative instruments we use consist primarily of futures, options and swaps traded on the NYMEX, ICE and in over-the-counter transactions.  Over-the-counter transactions include commodity swap and option contracts entered into with financial institutions and other energy companies.  All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into AOCI and recognized in revenues or purchases and related costs in the periods during which the underlying physical transactions occur. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) are recorded on the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

 

Interest Rate Risk Hedging

 

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

 

As of June 30, 2009, we had one outstanding interest-rate swap by which we receive fixed interest payments and pay floating-rate interest payments based on six-month LIBOR plus a spread of  1.85% on a quarterly basis.  The swap has a notional amount of $20 million with a fixed rate of 7.13% and terminates in 2014.  The swap is subject to a call option whereby our counterparty has the right to call the swap for approximately $1 million.  Our outstanding interest-rate swap is not designated for hedge accounting.   However, the interest-rate swap serves as an economic hedge in the event that market interest rates decline below the fixed interest rate of the underlying debt.  During June 2009, we received notice from our counterparty of their intention to call the swap.  As a result, the swap was called in July 2009 upon our receipt of the termination payment.

 

Currency Exchange Rate Risk Hedging

 

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

 

As of June 30, 2009, our outstanding foreign currency derivatives also include derivatives used to hedge Canadian Dollar-denominated crude oil purchases and sales.  We may from time to time hedge the commodity price risk associated with a Canadian Dollar-denominated commodity transaction with a U.S. Dollar-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 June 30, 2009, our open foreign exchange derivatives consisted of forward exchange contracts that exchange Canadian Dollars for U.S. Dollars on a net basis as follows (in millions):

 

 

 

Canadian Dollars

 

U.S. Dollars

 

Average Exchange Rate

 

2009

 

$

29

 

$

25

 

CAD $1.15 to US $1.00

 

2010

 

$

31

 

$

27

 

CAD $1.14 to US $1.00

 

2011

 

$

3

 

$

3

 

CAD $1.01 to US $1.00

 

2012

 

$

3

 

$

3

 

CAD $1.01 to US $1.00

 

2013

 

$

9

 

$

9

 

CAD $1.00 to US $1.00

 

 

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

 

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Table of Contents

 

Summary of Financial Impact

 

The majority of our derivative activity relates to our commodity price risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, LPG, natural gas and refined products, as well as with respect to anticipated purchases, sales and transportation of these commodities. The majority of our derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective, as defined in SFAS 133, in offsetting changes in cash flows of the hedged items, are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as operating cash flows in our consolidated statements of cash flows.

 

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

 

DERIVATIVES IN SFAS 133 CASH FLOW HEDGING RELATIONSHIPS:

 

 

 

 

 

Three Months Ended June 30, 2009

 

Six Months Ended June 30, 2009

 

 

 

Location of Gain/(Loss)

 

Amount of Gain/(Loss)
Reclassified from AOCI
into Income (Effective
Portion)

 

Amount of Gain/(Loss)
Recognized in Income
on Derivatives
(Ineffective Portion)

 

Amount of Gain/(Loss)
Reclassified from AOCI
into Income (Effective
Portion)

 

Amount of Gain/(Loss)
Recognized in Income
on Derivatives
(Ineffective Portion)

 

Commodity contracts

 

Crude oil, refined products and LPG sales and related revenues

 

$

17

 

$

(7

)

$

144

 

$

(8

)

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Crude oil, refined products and LPG purchases and related costs

 

1

 

 

(31

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

Interest income and other income (expense), net

 

 

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

$

18

 

$

(7

)

$

118

 

$

(8

)

 

DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS UNDER SFAS 133:

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

 

 

June 30, 2009

 

June 30, 2009

 

 

 

Location of Gain or (Loss) Recognized in Income on Derivative

 

Amount of Gain/(Loss)
Recognized in Income on
Derivatives

 

Amount of Gain/(Loss)
Recognized in Income on
Derivatives

 

Commodity contracts

 

Crude oil, refined products and LPG sales and related revenues

 

$

35

 

$

6

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Crude oil, refined products and LPG purchases and related costs

 

20

 

115

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Interest income and other income (expense), net

 

 

(1

)

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

Crude oil, refined products and LPG sales and related revenues

 

5

 

5

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

Crude oil, refined products and LPG purchases and related costs

 

2

 

(3

)

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

Interest income and other income (expense), net

 

(2

)

(2

)

 

 

 

 

 

 

 

 

Total

 

 

 

$

60

 

$

120

 

 

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Table of Contents

 

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet as of June 30, 2009 (in millions):

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

Balance Sheet

 

 

 

 

Balance Sheet

 

 

 

 

 

Location

 

Fair Value

 

 

Location

 

Fair Value

 

Derivatives designated as hedging instruments under SFAS 133:

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Other current assets

 

$

94

 

 

Other current liabilities

 

$

(98

)

 

 

Other long-term assets

 

48

 

 

Other long-term liabilities

 

 

Interest rate contracts

 

Other current assets

 

 

 

Other current liabilities

 

 

 

 

Other long-term assets

 

 

 

Other long-term liabilities

 

 

Foreign exchange contracts

 

Other current assets

 

1

 

 

Other current liabilities

 

 

 

 

Other long-term assets

 

5

 

 

Other long-term liabilities

 

(1

)

Total derivatives designated as hedging instruments under SFAS 133

 

 

 

$

148

 

 

 

 

$

(99

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments under SFAS 133:

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Other current assets

 

$

102

 

 

Other current liabilities

 

$

(113

)

 

 

Other long-term assets

 

91

 

 

Other long-term liabilities

 

(57

)

Interest rate contracts

 

Other current assets

 

1

 

 

Other current liabilities

 

 

 

 

Other long-term assets

 

 

 

Other long-term liabilities

 

 

Foreign exchange contracts

 

Other current assets

 

1

 

 

Other current liabilities

 

(2

)

 

 

Other long-term assets

 

 

 

Other long-term liabilities

 

 

Total derivatives not designated as hedging instruments under SFAS 133

 

 

 

$

195

 

 

 

 

$

(172

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

343

 

 

 

 

$

(271

)

 

As of June 30, 2009, there was a net loss of $42 million deferred in AOCI.  The total amount of deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the related physical purchase or delivery of the underlying commodity, (ii) interest expense accruals associated with the underlying debt instruments and (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain Canadian Dollar-denominated intercompany interest receivables. Of the total net loss deferred in AOCI at June 30, 2009, a net loss of approximately $106 million is expected to be reclassified to earnings in the next twelve months. Of the remaining deferred gain in AOCI, approximately 75% is expected to be reclassified to earnings prior to 2012 with the remaining deferred gain being reclassified to earnings through 2018. Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

 

During the three months ended June 30, 2009 and 2008, no amounts were reclassified from AOCI to earnings as a result of forecasted transactions no longer considered to be probable of occurring.  During the six months ended June 30, 2009, we reclassed a deferred gain of approximately $6 million from AOCI to other income as a result of anticipated hedge transactions that are no longer considered to be probable of occurring.  During the six months ended June 30, 2008, no amounts were reclassed from AOCI as a result of anticipated hedge transactions that are no longer considered to be probable of occurring.

 

Amounts of gain/(loss) recognized in AOCI on derivatives (effective portion) during the three and six months ended June 30, 2009 are as follows (in millions):

 

 

 

Three Months Ended
June 30, 2009

 

Six Months Ended
June 30, 2009

 

Commodity contracts

 

$

(104

)

$

(82

)

Foreign exchange contracts

 

(4

)

(2

)

Total

 

$

(108

)

$

(84

)

 

We do not enter into master netting agreements with our derivative counterparties, nor do we offset the assets and liabilities associated with the fair value of our derivatives with amounts we have recognized related to our right to receive or our obligation to pay cash collateral. When we deposit cash collateral with our brokers, we recognize a broker receivable, which is a component of our accounts receivable. The account equity in our brokerage accounts is a combination of our cash balance and the fair value of our open derivatives within our brokerage account.  When our account equity is less than our initial margin requirement we are required to post margin.  Our broker receivable was approximately $5 million and $81 million as of June 30, 2009 and December 31, 2008, respectively.  At June 30, 2009 and 2008, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

 

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009. As required by SFAS 157, financial assets and liabilities are classified in their

 

17



Table of Contents

 

entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

 

 

    

Fair Value as of June 30, 2009
(in millions)

 

 

Fair Value as of December 31, 2008
(in millions)

 

Recurring Fair Value Measures

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

289

 

$

12

 

$

34

 

$

335

 

 

$

235

 

$

9

 

$

112

 

$

356

 

Interest rate derivatives

 

 

 

1

 

1

 

 

 

 

5

 

5

 

Foreign currency derivatives

 

 

 

7

 

7

 

 

 

 

18

 

18

 

Total assets at fair value

 

$

289

 

$

12

 

$

42

 

$

343

 

 

$

235

 

$

9

 

$

135

 

$

379

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

(224

)

$

 

$

(44

)

$

(268

)

 

$

(330

)

$

 

$

(56

)

$

(386

)

Foreign currency derivatives

 

 

 

(3

)

(3

)

 

 

 

(5

)

(5

)

Total liabilities at fair value

 

$

(224

)

$

 

$

(47

)

$

(271

)

 

$

(330

)

$

 

$

(61

)

$

(391

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net asset/(liability) at fair value

 

$

65