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, 2011

 

OR

 

o

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

 

Commission file number: 1-14569

 


 

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

76-0582150

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

333 Clay Street, Suite 1600, Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

(713) 646-4100

(Registrant’s telephone number, including area code)

 


 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x  Yes   o  No

 

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

 

Large accelerated filer  x

 

Accelerated filer  o

 

Non-accelerated filer  o

 

Smaller reporting company  o

 

 

 

 

(Do not check if a smaller
reporting company)

 

 

 

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

 

As of August 2, 2011, there were 149,357,119 Common Units outstanding.

 

 

 



Table of Contents

 

 PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

 

TABLE OF CONTENTS

 

 

 

Page

PART I. FINANCIAL INFORMATION

 

3

Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

 

3

Condensed Consolidated Balance Sheets: June 30, 2011 and December 31, 2010

 

3

Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 2011 and 2010

 

4

Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 2011 and 2010

 

5

Condensed Consolidated Statement of Partners’ Capital: For the six months ended June 30, 2011

 

6

Condensed Consolidated Statements of Comprehensive Income: For the three and six months ended June 30, 2011 and 2010

 

6

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the six months ended June 30, 2011

 

6

Notes to Condensed Consolidated Financial Statements:

 

7

1. Organization and Basis of Presentation

 

7

2. Recent Accounting Pronouncements

 

8

3. Trade Accounts Receivable

 

9

4. Acquisitions

 

9

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

 

11

6. Goodwill

 

11

7. Debt

 

12

8. Net Income Per Limited Partner Unit

 

13

9. Income Taxes

 

14

10. Partners’ Capital and Distributions

 

14

11. Equity Compensation Plans

 

16

12. Derivatives and Risk Management Activities

 

16

13. Commitments and Contingencies

 

25

14. Operating Segments

 

28

15. Related Party Transactions

 

29

16. Supplemental Condensed Consolidating Financial Information

 

30

 

 

 

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

 

36

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

52

Item 4. CONTROLS AND PROCEDURES

 

52

 

 

 

PART II. OTHER INFORMATION

 

53

Item 1. LEGAL PROCEEDINGS

 

53

Item 1A. RISK FACTORS

 

53

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

 

53

Item 3. DEFAULTS UPON SENIOR SECURITIES

 

53

Item 4. [REMOVED AND RESERVED]

 

53

Item 5. OTHER INFORMATION

 

53

Item 6. EXHIBITS

 

53

SIGNATURES

 

57

 

2


 


Table of Contents

 

PART I. FINANCIAL INFORMATION

 

Item  1.                                 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except units)

 

 

 

June 30,

 

December 31,

 

 

 

2011

 

2010

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

23

 

$

36

 

Restricted cash

 

 

20

 

Trade accounts receivable and other receivables, net

 

3,047

 

2,746

 

Inventory

 

1,452

 

1,491

 

Other current assets

 

111

 

88

 

Total current assets

 

4,633

 

4,381

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

8,498

 

7,814

 

Accumulated depreciation

 

(1,222

)

(1,123

)

 

 

7,276

 

6,691

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

1,692

 

1,376

 

Linefill and base gas

 

549

 

519

 

Long-term inventory

 

136

 

154

 

Investments in unconsolidated entities

 

195

 

200

 

Other, net

 

432

 

382

 

Total assets

 

$

14,913

 

$

13,703

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

3,265

 

$

2,738

 

Short-term debt

 

536

 

1,326

 

Other current liabilities

 

182

 

151

 

Total current liabilities

 

3,983

 

4,215

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discount of $14 and $12, respectively

 

4,761

 

4,363

 

Long-term debt under credit facilities and other

 

234

 

268

 

Other long-term liabilities and deferred credits

 

252

 

284

 

Total long-term liabilities

 

5,247

 

4,915

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 13)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (149,357,119 and 141,199,175 units outstanding, respectively)

 

5,022

 

4,234

 

General partner

 

128

 

108

 

Total partners’ capital excluding noncontrolling interests

 

5,150

 

4,342

 

Noncontrolling interests

 

533

 

231

 

Total partners’ capital

 

5,683

 

4,573

 

Total liabilities and partners’ capital

 

$

14,913

 

$

13,703

 

 

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

 

3



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(unaudited)

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

Supply & Logistics segment revenues

 

$

8,586

 

$

5,901

 

$

16,021

 

$

11,813

 

Transportation segment revenues

 

147

 

139

 

288

 

277

 

Facilities segment revenues

 

126

 

84

 

244

 

158

 

Total revenues

 

8,859

 

6,124

 

16,553

 

12,248

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

8,202

 

5,641

 

15,281

 

11,263

 

Field operating costs

 

223

 

171

 

420

 

334

 

General and administrative expenses

 

73

 

56

 

143

 

117

 

Depreciation and amortization

 

63

 

64

 

126

 

131

 

Total costs and expenses

 

8,561

 

5,932

 

15,970

 

11,845

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

298

 

192

 

583

 

403

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

4

 

1

 

5

 

2

 

Interest expense (net of capitalized interest of $6, $3, $11 and $9, respectively)

 

(62

)

(62

)

(128

)

(120

)

Other income/(expense), net

 

2

 

2

 

(20

)

(1

)

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

242

 

133

 

440

 

284

 

Current income tax benefit/(expense)

 

(8

)

1

 

(18

)

(1

)

Deferred income tax benefit/(expense)

 

(1

)

(1

)

(4

)

1

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

233

 

133

 

418

 

284

 

Less: Net income attributable to noncontrolling interests

 

(8

)

(2

)

(10

)

(2

)

NET INCOME ATTRIBUTABLE TO PLAINS

 

$

225

 

$

131

 

$

408

 

$

282

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PLAINS:

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

171

 

$

90

 

$

305

 

$

201

 

GENERAL PARTNER

 

$

54

 

$

41

 

$

103

 

$

81

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

1.14

 

$

0.65

 

$

2.04

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

1.13

 

$

0.65

 

$

2.03

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

149

 

136

 

146

 

136

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

150

 

137

 

147

 

137

 

 

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

 

4



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Six Months Ended

 

 

 

June 30,

 

 

 

2011

 

2010

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

418

 

$

284

 

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

 

 

 

 

 

Depreciation and amortization

 

126

 

131

 

Equity compensation expense

 

46

 

33

 

Gain on sale of linefill

 

(15

)

(17

)

Net cash received for terminated interest rate or foreign currency hedging instruments

 

12

 

 

Other

 

5

 

8

 

Changes in assets and liabilities, net of acquisitions

 

380

 

(156

)

Net cash provided by operating activities

 

972

 

283

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(751

)

(184

)

Change in restricted cash

 

20

 

 

Additions to property, equipment and other

 

(287

)

(215

)

Net cash received/(paid) for sales and purchases of linefill and base gas

 

(6

)

18

 

Other investing activities

 

(3

)

3

 

Net cash used in investing activities

 

(1,027

)

(378

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net repayments on PAA’s revolving credit facility

 

(592

)

(150

)

Net borrowings/(repayments) on PNG’s revolving credit facility

 

(34

)

205

 

Net borrowings/(repayments) on PAA’s hedged inventory facility

 

(200

)

100

 

Proceeds from the issuance of senior notes

 

597

 

 

Repayments of senior notes

 

(200

)

 

Net proceeds from the issuance of common units (Note 10)

 

503

 

 

Cash received for sale of noncontrolling interest in a subsidiary

 

370

 

268

 

Distributions paid to common unitholders (Note 10)

 

(280

)

(253

)

Distributions paid to general partner (Note 10)

 

(102

)

(82

)

Distributions to noncontrolling interests

 

(16

)

(1

)

Other financing activities

 

(3

)

(1

)

Net cash provided by financing activities

 

43

 

86

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(1

)

(1

)

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(13

)

(10

)

Cash and cash equivalents, beginning of period

 

36

 

25

 

Cash and cash equivalents, end of period

 

$

23

 

$

15

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

123

 

$

123

 

 

 

 

 

 

 

Cash paid for income taxes, net of amounts refunded

 

$

1

 

$

20

 

 

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

 

5



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

 

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

 

 

 

 

Common Units

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Units

 

Amount

 

Partner

 

Interests

 

Interests

 

Capital

 

 

 

(unaudited)

 

Balance, December 31, 2010

 

141

 

$

4,234

 

$

108

 

$

4,342

 

$

231

 

$

4,573

 

Net income

 

 

305

 

103

 

408

 

10

 

418

 

Sale of noncontrolling interest in a subsidiary (Note 10)

 

 

63

 

1

 

64

 

306

 

370

 

Distributions

 

 

(280

)

(102

)

(382

)

(16

)

(398

)

Issuance of common units

 

8

 

493

 

10

 

503

 

 

503

 

Issuance of common units under LTIP

 

 

13

 

 

13

 

 

13

 

Other comprehensive income

 

 

186

 

4

 

190

 

 

190

 

Equity compensation expense

 

 

 

8

 

4

 

12

 

2

 

14

 

Balance, June 30, 2011

 

149

 

$

5,022

 

$

128

 

$

5,150

 

$

533

 

$

5,683

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

233

 

$

133

 

$

418

 

$

284

 

Other comprehensive income/(loss)

 

220

 

(45

)

190

 

19

 

Comprehensive income

 

453

 

88

 

608

 

303

 

Less: Comprehensive income attributable to noncontrolling interests

 

(8

)

(2

)

(10

)

(2

)

Comprehensive income attributable to Plains

 

$

445

 

$

86

 

$

598

 

$

301

 

 

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

 

 

Derivative

 

Translation

 

 

 

 

 

 

 

Instruments

 

Adjustments

 

Other

 

Total

 

 

 

(unaudited)

 

Balance, December 31, 2010

 

$

(79

)

$

198

 

$

(1

)

$

118

 

Reclassification adjustments

 

233

 

 

 

233

 

Deferred loss on cash flow hedges, net of tax

 

(95

)

 

 

(95

)

Currency translation adjustment

 

 

52

 

 

52

 

Total period activity

 

138

 

52

 

 

190

 

Balance, June 30, 2011

 

$

59

 

$

250

 

$

(1

)

$

308

 

 

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

 

6


 


Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO 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. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also engage in the development and operation of natural gas storage facilities. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 14 for further detail of our three operating segments.

 

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

 

Definitions

 

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

 

AOCI

=

Accumulated other comprehensive income

Bcf

=

Billion cubic feet

Btu

=

British thermal unit

CAD

=

Canadian dollar

DERs

=

Distribution equivalent rights

EBITDA

=

Earnings before interest, taxes, depreciation and amortization

FASB

=

Financial Accounting Standards Board

FERC

=

Federal Energy Regulatory Commission

ICE

=

IntercontinentalExchange

IFRS

=

International Financial Reporting Standards

LIBOR

=

London Interbank Offered Rate

LPG

=

Liquefied petroleum gas and other natural gas-related products

LTIPs

=

Long-term incentive plans

Mcf

=

Thousand cubic feet

MLP

=

Master limited partnership

MTBE

=

Methyl tertiary-butyl ether

Nexen

=

Nexen Holdings U.S.A. Inc.

NPNS

=

Normal purchases and normal sales

NYMEX

=

New York Mercantile Exchange

Pacific

=

Pacific Energy Partners, L.P.

PLA

=

Pipeline loss allowance

PNG

=

PAA Natural Gas Storage, L.P.

PNGS

=

PAA Natural Gas Storage, LLC

RMPS

=

Rocky Mountain Pipeline System

SEC

=

Securities and Exchange Commission

SG Resources

=

SG Resources Mississippi, LLC

U.S. GAAP

=

Generally accepted accounting principles in the United States

USD

=

United States dollar

WTI

=

West Texas intermediate

WTS

=

West Texas sour

 

7



Table of Contents

 

Basis of Consolidation and Presentation

 

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2010 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation. As discussed further below, certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to Plains or total partners’ capital. The condensed balance sheet data as of December 31, 2010 was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. The results of operations for the three and six months ended June 30, 2011 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.

 

Revision of Prior Period Consolidated Statement of Cash Flows

 

During the second quarter of 2010, PNG completed its IPO of 13.5 million common units representing limited partner interests. Net proceeds received by PNG from the sale of the common units of approximately $268 million were presented in our financial statements for the quarter ended June 30, 2010 as cash flows from investing activities.  Upon further evaluation, we now believe that this activity should have been presented as cash flows from financing activities.  We have determined that the impact of this reclassification on our consolidated statement of cash flows for the six months ended June 30, 2010 is not material.

 

The following captions within the prior period consolidated statement of cash flows were impacted (in millions):

 

 

 

Amounts Previously
Reported

 

As Revised

 

Net cash used in investing activities

 

$

(110

)

$

(378

)

Net cash provided by/(used in) financing activities

 

$

(182

)

$

86

 

 

Note 2—Recent Accounting Pronouncements

 

Other than as discussed below and in our 2010 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the six months ended June 30, 2011 that are of significance or potential significance to us.

 

In December 2010, the FASB issued updated accounting guidance related to the calculation of the carrying amount of a reporting unit when performing the first step of a goodwill impairment test.  More specifically, this update will require an entity to use an equity premise when performing the first step of a goodwill impairment test, and if a reporting unit has a zero or negative carrying amount, the entity must assess and consider qualitative factors to determine whether it is more likely than not that a goodwill impairment exists. The new accounting guidance is effective for impairment tests performed during fiscal years (and interim periods within those years) that begin after December 15, 2010.  We adopted this guidance on January 1, 2011; however, as we currently do not have any reporting units with a zero or negative carrying amount, our adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

 

In December 2010, the FASB issued updated accounting guidance to clarify that pro forma disclosures should be presented as if a business combination that is determined to be material on an individual or aggregate basis occurred at the beginning of the prior annual period for purposes of preparing both the current reporting period and the prior reporting period pro forma financial information. These disclosures should be accompanied by a narrative description about the nature and amount of material, nonrecurring pro forma adjustments. The new accounting guidance is effective for business combinations consummated in periods beginning after December 15, 2010 and should be applied prospectively as of the date of adoption.  We adopted this guidance on January 1, 2011. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

 

8



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In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. The fair value hierarchy consists of designation to one of three levels based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, level 2 measurements generally reflect the use of significant observable inputs and level 3 measurements typically utilize significant unobservable inputs. This new guidance requires a gross presentation of activities within the level 3 rollforward. This guidance was effective for annual and interim reporting periods beginning after December 15, 2010. We adopted this guidance on January 1, 2011. See Note 12 for additional disclosure. Our adoption did not have any material impact on our financial position, results of operations, or cash flows.

 

Accounting Pronouncements Not Yet Effective

 

In June 2011, the FASB issued new guidance regarding the presentation of comprehensive income. This guidance requires entities to present reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement in which the components of net income and components of other comprehensive income are presented. It also eliminates the current option under U.S. GAAP to present components of other comprehensive income within the statement of changes in stockholders’ equity. The components of comprehensive income will be required to be presented within either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance is effective for interim and annual periods beginning after December 15, 2011, with earlier adoption permitted. Since this issuance only impacts the presentation of such financial information, adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows.

 

In May 2011, the FASB issued guidance to amend certain measurement and disclosure requirements related to fair value in an effort to improve consistency with international reporting standards. This guidance is effective prospectively for interim and annual reporting periods beginning after December 15, 2011. Early adoption is not permitted. The adoption of this guidance is not expected to have a 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 June 30, 2011 and December 31, 2010, 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 approximately $6 million and $5 million at June 30, 2011 and December 31, 2010, respectively. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

At June 30, 2011 and December 31, 2010, we had received approximately $190 million and $197 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables between the two) that cover a significant part of our transactions and also serve to mitigate credit risk.

 

Note 4—Acquisitions

 

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

 

Southern Pines Acquisition

 

On February 9, 2011, PNG acquired 100% of the equity interests in SG Resources from SGR Holdings, L.L.C. (the “Southern Pines Acquisition”) for an aggregate purchase price of approximately $752 million in cash, net of cash acquired, which is subject to finalization of certain post-closing adjustments. The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”), a FERC-regulated, salt-cavern natural gas storage facility located in Greene County, Mississippi. In connection with this acquisition, PNG obtained financing through a private placement of PNG common units to third-party purchasers, and we purchased additional PNG common units. See Note 10 for further discussion.

 

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The purchase price allocation related to the Southern Pines Acquisition is preliminary and subject to change, pending completion of internal valuation procedures primarily related to the valuation of intangible assets and the various components of the property and equipment acquired. The preliminary allocation of fair value to intangible assets below is comprised of a tax abatement valued at approximately $15 million and contracts valued at approximately $77 million, which have lives ranging from 2 to 10 years. Amortization of customer contracts under the declining balance method of amortization is estimated to be approximately $13 million, $14 million, $13 million, $11 million and $8 million for the five full or partial calendar years following the acquisition date, respectively. Goodwill or indefinite lived intangible assets will not be subject to depreciation or amortization, but will be subject to periodic impairment testing and, if necessary, will be written down to fair value should circumstances warrant.  We expect to finalize our purchase price allocation during 2011. The preliminary purchase price allocation is as follows (in millions):

 

 

 

 

 

 

Average

 

 

 

 

 

Depreciable

 

Description

 

Amount

 

Life (in years)

 

Inventory

 

$

14

 

N/A

 

Property and equipment, net

 

341

 

5 - 70

 

Base gas

 

3

 

N/A

 

Other working capital, net of cash acquired

 

1

 

N/A

 

Intangible assets

 

92

 

2 - 10

 

Goodwill

 

301

 

N/A

 

Total

 

$

752

 

 

 

 

Several factors contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired.  Such factors include the strategic location of the Southern Pines facility, the limited alternative locations and the extended lead times required to develop and construct such facility, along with its operational flexibility, organic expansion capabilities and synergies anticipated to be obtained from combining Southern Pines with our existing asset base. Through June 30, 2011, we have incurred approximately $4 million of acquisition-related costs, which are included in general and administrative expenses in our condensed consolidated statement of operations. This acquisition is reflected within our facilities segment.

 

In May 2011, PNG entered into an agreement with the former owners of SG Resources with respect to certain outstanding issues and purchase price adjustments as well as the distribution of the remaining 5% of the purchase price that was escrowed at closing (totaling $37 million). Pursuant to this agreement, PNG received approximately $10 million and the balance was remitted to the former owners. Funds received by PNG will be used to fund anticipated facility development and other related costs identified subsequent to closing.  Additionally, the parties executed releases of any existing and future claims, subject to customary carve-outs.

 

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Note 5—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 thousands of Mcf and total value in millions):

 

 

 

 

June 30, 2011

 

December 31, 2010

 

 

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

11,581

 

barrels

 

$

1,108

 

$

95.67

 

14,132

 

barrels

 

$

1,100

 

$

77.84

 

LPG

 

5,077

 

barrels

 

326

 

$

64.21

 

7,395

 

barrels

 

366

 

$

49.49

 

Natural gas (2)

 

3,006

 

Mcf

 

13

 

$

4.32

 

13

 

Mcf

 

 

$

3.87

 

Other

 

N/A

 

 

 

5

 

N/A

 

N/A

 

 

 

25

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,452

 

 

 

 

 

 

 

1,491

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,227

 

barrels

 

504

 

$

54.62

 

9,159

 

barrels

 

478

 

$

52.19

 

Natural gas (2)

 

12,425

 

Mcf

 

42

 

$

3.38

 

11,194

 

Mcf

 

37

 

$

3.31

 

LPG

 

56

 

barrels

 

3

 

$

53.57

 

77

 

barrels

 

4

 

$

51.95

 

Linefill and base gas subtotal

 

 

 

 

 

549

 

 

 

 

 

 

 

519

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,727

 

barrels

 

128

 

$

74.12

 

1,761

 

barrels

 

128

 

$

72.69

 

LPG

 

150

 

barrels

 

8

 

$

53.33

 

505

 

barrels

 

26

 

$

51.49

 

Long-term inventory subtotal

 

 

 

 

 

136

 

 

 

 

 

 

 

154

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

2,137

 

 

 

 

 

 

 

$

2,164

 

 

 

 


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

 

(2)                      The volumetric ratio of Mcf of natural gas to crude Btu equivalent is 6:1; thus, natural gas volumes can be approximately converted to barrels by dividing by 6.

 

Note 6 — Goodwill

 

The table below reflects our changes in goodwill for the period indicated (in millions):

 

 

 

Transportation

 

Facilities

 

Supply & Logistics

 

Total (1)

 

Balance, December 31, 2010

 

$

640

 

$

308

 

$

428

 

$

1,376

 

2011 Goodwill Related Activity:

 

 

 

 

 

 

 

 

 

Southern Pines Acquisition (2)

 

 

301

 

 

301

 

Purchase accounting adjustments (2)

 

 

 

10

 

10

 

Foreign currency translation adjustments

 

7

 

 

1

 

8

 

Other

 

 

 

(3

)

(3

)

Balance, June 30, 2011

 

$

647

 

$

609

 

$

436

 

$

1,692

 

 


(1)                      As of June 30, 2011, we do not have any material accumulated impairment losses.

 

(2)                      Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation. This preliminary goodwill balance may be adjusted when the purchase price allocation is finalized.

 

We completed our annual goodwill impairment test (as of June 30) and determined that there was no impairment of goodwill.

 

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Note 7—Debt

 

Debt consisted of the following (in millions):

 

 

 

June 30,

 

December 31,

 

 

 

2011

 

2010

 

SHORT-TERM DEBT

 

 

 

 

 

Credit Facilities:

 

 

 

 

 

Senior secured hedged inventory facility bearing a weighted-average interest rate of 2.1% for both periods presented

 

$

300

 

$

500

 

PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 1.1% and 0.7% at June 30, 2011 and December 31, 2010, respectively (1)

 

234

 

824

 

Other

 

2

 

2

 

Total short-term debt

 

536

 

1,326

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

Senior Notes:

 

 

 

 

 

4.25% senior notes due September 2012 (2)

 

500

 

500

 

7.75% senior notes due October 2012 (3)

 

 

200

 

5.63% senior notes due December 2013

 

250

 

250

 

5.25% senior notes due June 2015

 

150

 

150

 

3.95% senior notes due September 2015

 

400

 

400

 

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

 

5.00% senior notes due February 2021 (4)

 

600

 

 

6.70% senior notes due May 2036

 

250

 

250

 

6.65% senior notes due January 2037

 

600

 

600

 

Unamortized discounts

 

(14

)

(12

)

Senior notes, net of unamortized discounts

 

4,761

 

4,363

 

Credit Facilities and Other:

 

 

 

 

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.9% and 3.2% at June 30, 2011 and December 31, 2010, respectively

 

226

 

260

 

Other

 

8

 

8

 

Total long-term debt (1)

 

4,995

 

4,631

 

Total debt (5)

 

$

5,531

 

$

5,957

 

 


(1)                      We classify as short-term any borrowings under our PAA senior unsecured revolving credit facility. These borrowings are designated as working capital borrowings, must be repaid within one year and are primarily for hedged LPG and crude oil inventory and NYMEX and ICE margin deposits.

 

(2)                      The proceeds from these notes are being used to supplement capital available from our hedged inventory facility. At June 30, 2011 and December 31, 2010, approximately $500 million and $466 million, respectively, had been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities.

 

(3)                      On February 7, 2011, our $200 million, 7.75% senior notes due 2012 were redeemed in full.  In conjunction with the early redemption, we recognized a loss of approximately $23 million, recorded to Other income/(expense), net in our condensed consolidated statement of operations. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

 

(4)                      In January 2011, we completed the issuance of $600 million, 5.00% senior notes due 2021. The senior notes were sold at 99.521% of face value. Interest payments are due on February 1 and August 1 of each year, beginning on August 1, 2011. We used the net proceeds from this offering to repay outstanding indebtedness under our credit facilities and for general partnership purposes.

 

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(5)                      Our fixed-rate senior notes have a face value of approximately $4.8 billion and $4.4 billion as of June 30, 2011 and December 31, 2010, respectively. We estimate the aggregate fair value of these notes as of June 30, 2011 and December 31, 2010 to be approximately $5.2 billion and $4.7 billion, respectively. 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. We estimate that the carrying value of outstanding borrowings under our credit facilities approximates fair value as interest rates reflect current market rates.

 

PAA 364-Day Credit Facility

 

In January 2011, we entered into a 364-day senior unsecured credit facility with an aggregate borrowing capacity of $500 million. This credit facility has a maximum debt-to-EBITDA coverage ratio of 4.75 to 1.00 (5.50 to 1.00 during an acquisition period) and matures at the earlier of January 2012 or the refinancing of our PAA senior unsecured revolving credit facility. As set forth in the agreement, borrowings under this facility bear interest at our election at either LIBOR plus an applicable margin (based on the credit rating of our long-term senior unsecured debt), or a base rate. Commitment fees are payable at rates between 0.15% and 0.40%, also determined based on the credit rating of our long-term senior unsecured debt. Borrowings may be used for any partnership purpose. There were no outstanding borrowings under this facility at June 30, 2011.

 

Letters of Credit

 

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil.  At June 30, 2011 and December 31, 2010, we had outstanding letters of credit of approximately $95 million and $75 million, respectively.

 

Note 8—Net Income Per Limited Partner Unit

 

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2011 and 2010 (amounts in millions, except per unit data):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

225

 

$

131

 

$

408

 

$

282

 

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

 

(50

)

(39

)

(97

)

(77

)

Subtotal

 

175

 

92

 

311

 

205

 

Less: General partner 2% ownership (1) 

 

(4

)

(2

)

(6

)

(4

)

Net income available to limited partners

 

171

 

90

 

305

 

201

 

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

 

(1

)

(1

)

(6

)

(3

)

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

 

$

170

 

$

89

 

$

299

 

$

198

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

149

 

136

 

146

 

136

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

150

 

137

 

147

 

137

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

1.14

 

$

0.65

 

$

2.04

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

1.13

 

$

0.65

 

$

2.03

 

$

1.45

 

 

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(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 11) that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

 

Note 9—Income Taxes

 

U.S. Federal and State Taxes

 

As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the three and six months ended June 30, 2011 and 2010 was immaterial.

 

Canadian Federal and Provincial Taxes

 

In 2010 and prior years, our Canadian operations were operated through a combination of corporate entities subject to Canadian federal and provincial taxes and a limited partnership which was treated as a flow-through entity for tax purposes. Due to changes in Canadian legislation and the Fifth Protocol to the U.S./Canada Tax Treaty, we restructured our Canadian investment on January 1, 2011. As of this date, all of our Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes (flow through for U.S. tax purposes) and that are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from Canada to other Plains entities are subject to Canadian withholding tax that is treated as a distribution to unitholders.

 

Note 10—Partners’ Capital and Distributions

 

Noncontrolling Interests in a Subsidiary

 

As of June 30, 2011, noncontrolling interests consisted of the following: (i) an approximate 36% interest in PNG and (ii) a 25% interest in SLC Pipeline LLC.

 

During February 2011, in connection with the Southern Pines Acquisition, PNG completed a private placement of approximately 17.4 million PNG common units to third-party purchasers for net proceeds of approximately $370 million. In addition, we purchased approximately 10.2 million PNG common units for approximately $230 million, including our proportionate general partner contribution of $12 million (collectively, “the PNG offering”). Also, during May 2011, a portion of the PNG Transaction Grants vested and were settled with 58,672 PNG units, which were owned by us.  See Note 10 to our Consolidated Financial Statements included in Part IV of our 2010 Annual Report on Form 10-K for further detail regarding the “PNG Transaction Grants.” As a result of these transactions, our aggregate ownership interest in PNG decreased from approximately 77% to approximately 64%. The following table sets forth our ownership changes in the limited partner units of PNG from December 31, 2010 to June 30, 2011 (units in millions):

 

 

 

December 31,
2010

 

February 2011
PNG Issuance

 

Transaction
Grants

 

June 30,
2011

 

PNG Units Owned by PAA:

 

 

 

 

 

 

 

 

 

Common Units

 

18.1

 

10.2

 

(0.1

)

28.2

 

Series A Subordinated Units

 

11.9

 

 

 

11.9

 

Series B Subordinated Units

 

13.5

 

 

 

13.5

 

Total PNG Units Owned by PAA

 

43.5

 

10.2

 

(0.1

)

53.6

 

 

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In addition to our limited partner interest, we also own the general partner’s 2% interest and the incentive distribution rights in PNG.

 

In conjunction with the PNG offering, we recorded an increase in noncontrolling interest of $306 million and an increase to our partners’ capital of approximately $64 million. The increases result from the portion of the proceeds attributable to the respective ownership interests in PNG, adjusted for the impact of the dilution of our ownership interest resulting from this transaction.

 

The following table sets forth the impact of the changes in our ownership interest in PNG on our capital (in millions):

 

 

 

For the Six Months Ended

 

 

 

June 30,

 

 

 

2011

 

2010

 

Net income attributable to Plains

 

$

408

 

$

282

 

Transfers to the noncontrolling interests:

 

 

 

 

 

Increase in capital from sale of PNG units

 

64

 

101

 

Change from net income attributable to Plains and net transfers to the noncontrolling interest

 

$

472

 

$

383

 

 

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

 

 

 

For the Six Months Ended

 

 

 

June 30,

 

 

 

2011

 

2010

 

Beginning balance

 

$

231

 

$

63

 

Sale of noncontrolling interests in a subsidiary

 

306

 

167

 

Net income attributable to noncontrolling interests

 

10

 

2

 

Distributions to noncontrolling interests

 

(16

)

(1

)

Equity compensation expense

 

2

 

 

Ending Balance

 

$

533

 

$

231

 

 

PAA Distributions

 

The following table details the distributions paid during or pertaining to the first six months of 2011, 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

 

July 11, 2011

 

August 12, 2011 (1)

 

$

147

 

$

52

 

$

3

 

$

202

 

$

0.9825

 

April 11, 2011

 

May 13, 2011

 

$

145

 

$

50

 

$

3

 

$

198

 

$

0.9700

 

January 12, 2011

 

February 14, 2011

 

$

135

 

$

46

 

$

3

 

$

184

 

$

0.9575

 

 


(1)       Payable to unitholders of record at the close of business on August 2, 2011, for the period April 1, 2011 through June 30, 2011.

 

In conjunction with the closing of certain acquisitions, our general partner agreed to temporarily reduce the amounts due it as incentive distributions. Following the distribution in August 2011, the aggregate incentive distribution reductions remaining will be approximately $1 million. See Note 5 to our Consolidated Financial Statements included in Part IV of our 2010 Annual Report on Form 10-K for further detail regarding our “General Partner Incentive Distributions.”

 

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Table of Contents

 

PAA Equity Offerings

 

During the six months ended June 30, 2011, we completed an equity offering of our common units as shown in the table below (in millions, except per unit data):

 

 

 

 

 

 

 

 

 

General

 

 

 

 

 

 

 

 

 

Gross

 

Proceeds

 

Partner

 

 

 

Net

 

Date

 

Units Issued

 

Unit Price

 

from Sale

 

Contribution

 

Costs

 

Proceeds

 

March 2011 (1)

 

7,935,000

 

$

64.00

 

$

508

 

$

10

 

$

(15

)

$

503

 

 


(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.

 

Note 11—Equity Compensation Plans

 

For discussion of our equity compensation awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2010 Annual Report on Form 10-K.

 

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

 

 

 

PAA Units

 

 

PNG Units

 

 

 

Units

 

Weighted Average Grant
Date
Fair Value per Unit

 

 

Units

 

Weighted Average Grant
Date
Fair Value per Unit

 

Outstanding, December 31, 2010

 

4.4

 

$

41.69

 

 

1.0

 

$

20.55

 

Granted

 

0.3

 

$

54.50

 

 

 

$

 

Vested

 

(0.6

)

$

40.88

 

 

(0.1

)

$

23.67

 

Cancelled or forfeited

 

(0.1

)

$

41.56

 

 

 

$

 

Outstanding, June 30, 2011

 

4.0

 

$

43.06

 

 

0.9

 

$

20.41

 

 

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

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Equity compensation expense

 

$

27

 

$

14

 

$

46

 

$

33

 

LTIP unit vestings (1)

 

$

23

 

$

25

 

$

23

 

$

25

 

LTIP cash settled vestings

 

$

18

 

$

10

 

$

18

 

$

10

 

DER cash payments

 

$

1

 

$

1

 

$

2

 

$

2

 

 


(1)                      For the three and six months ended June 30, 2011, approximately $1 million relates to unit vestings which were settled with PNG units.

 

Note 12—Derivatives and Risk Management Activities

 

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on commodity price changes. We use various derivative instruments to (i) manage our exposure to commodity price risk as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate 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

 

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includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.

 

Commodity Price Risk Hedging

 

Our core business activities contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments. Our policy is (i) to only purchase product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not to acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. 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 operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of June 30, 2011, net derivative positions related to these activities included:

 

·      An approximate 212,900 barrels per day net long position (total of 6.4 million barrels) associated with our crude oil purchases, which was unwound ratably during July 2011 to match monthly average pricing.

 

·      A net short spread position averaging approximately 39,300 barrels per day (total of 21.5 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through January 2013.  These derivatives also hedge the margin associated with anticipated crude oil purchases.  These derivatives are time spreads consisting of offsetting purchases and sales between two different months, and other than for changes in the spreads, do not result in exposure to outright price movements.

 

·      A net short calender spread call options position averaging approximately 32,200 barrels per day (total of 5.9 million barrels) for the period August 2011 through January 2012.  These derivatives also hedge the margin associated with anticipated crude oil purchases.  These derivatives are time spreads between two different months, and other than for changes in the spreads, do not result in exposure to outright price movements.

 

·      Approximately 5,400 barrels per day on average (total of 2.9 million barrels) of WTS/WTI crude oil basis swaps through December 2012, which hedge anticipated sales of crude oil (WTI).  These derivatives are grade spreads between two different grades of crude oil, and other than for changes in the spreads, do not result in exposure to outright price movements.

 

·      Approximately 3,100 barrels per day on average (total of 0.9 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 March 2012.  These derivatives are cross-commodity spreads between butane and WTI, and other than for changes in the spreads, do not result in exposure to outright price movements.

 

Storage Capacity Utilization — We own approximately 70 million barrels of crude oil, LPG and refined products storage capacity other than that 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 June 30, 2011, we used derivatives to manage the risk of not utilizing approximately 3.8 million barrels per month of storage capacity through 2012. These positions are a combination of calendar spread options and 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. When we purchase and store inventory, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory. As of June 30, 2011, we had derivatives totaling approximately 9.4 million barrels hedging our inventory.  These positions are a combination of swaps and futures contracts.

 

We also purchase waterborne cargos of crude oil and may enter into derivatives to mitigate various price risks associated with the purchase and ultimate sale of crude inventory. As of June 30, 2011, we had approximately 0.5 million barrels of crude oil derivatives hedging the anticipated sale of such 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 June 30, 2011, our PLA hedges included (i) a net short position consisting of crude oil futures and swaps for an average of approximately 1,700 barrels per day (total of 2.9 million barrels) through December 2015, (ii) a long put option position of

 

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approximately 0.4 million barrels through December 2012 and (iii) a long call option position of approximately 0.4 million barrels through December 2012.

 

Natural Gas Purchases and Sales — Our gas storage facilities require minimum levels of natural gas (“base gas”) to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of June 30, 2011, we have a long futures position of approximately 0.7 Bcf, 3.0 Bcf of long swaps, and a long call option position of approximately 0.7 Bcf related to anticipated base gas purchases. Additionally, our natural gas commercial marketing group captures short-term market opportunities by leasing a portion of our owned or leased storage capacity to engage in related commercial marketing activities.  We use various derivatives, including index and basis swaps, to hedge anticipated purchases and sales of natural gas by our commercial marketing group.  As of June 30, 2011, we have a short swap position of approximately 6.6 Bcf related to anticipated sales of natural gas, and an approximate 6.3 Bcf long swap position related to anticipated purchases of natural gas.  Additionally, we have a net short calendar spread call option position of approximately 3.0 Bcf related to anticipated sales of natural gas. These calls in the aggregate do not result in exposure to outright price movements.

 

All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. We have determined that substantially all of our physical purchase and sale agreements qualify for the NPNS exclusion. 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 at fair value, with changes in fair value recognized in earnings.

 

Interest Rate Risk Hedging

 

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of June 30, 2011, AOCI includes deferred gains of $9 million that relate to open and terminated interest rate swaps and treasury locks that were designated for hedge accounting. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred gain related to these instruments is being amortized to interest expense over the original terms of the hedged debt instruments.

 

During June and July 2011, we entered into six forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2013. The following table summarizes the terms of our forward starting interest rate swaps (notional amounts in millions):

 

Hedged Transaction

 

Number and Types of
Derivatives Employed

 

Notional
Amount

 

Expected
Termination Date

 

Average Rate
Locked

 

Accounting
Treatment

 

Anticipated debt offering

 

3 forward starting swaps (30-year)

 

$

150

 

6/17/2013

 

4.35

%

Cash flow hedge

 

Anticipated debt offering

 

3 forward starting swaps (10-year)

 

$

150

 

6/15/2012

 

3.53

%

Cash flow hedge

 

 

During June 2011, PNG entered into two interest rate swaps to fix the interest rate on a portion of its revolving credit facility. The swaps have an aggregate notional amount of $50 million with an average fixed rate of 1.06% and terminate in June 2014.

 

Concurrent with our January 2011 senior notes issuance, we terminated three forward starting interest rate swaps. See Note 7 for additional disclosure. These swaps had an aggregate notional amount of $100 million and an average fixed rate of 3.6%. We received cash proceeds of $12 million associated with the termination of these swaps.

 

During July 2009, we entered into four interest rate swaps for 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 September 2011 and two of the swaps terminate in September 2012. The swaps that terminate in 2012 are designated as fair value hedges.

 

Currency Exchange Rate Risk Hedging

 

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 foreign currency derivatives to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. As of June 30, 2011, AOCI includes net deferred gains of $11

 

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million that relate to open and settled foreign currency derivatives that were designated for hedge accounting. These foreign currency derivatives hedge the cash flow variability associated with CAD-denominated interest payments on a CAD-denominated intercompany note as a result of changes in the exchange rate.

 

As of June 30, 2011, our outstanding foreign currency derivatives also include derivatives we use to hedge USD-denominated crude oil purchases and sales in Canada. In addition, we may from time to time hedge the commodity price risk associated with a CAD-denominated commodity transaction with a USD-denominated commodity derivative. In conjunction with entering into the commodity derivative, we may enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and are not designated for hedge accounting.

 

The following table summarizes our open forward exchange contracts that exchange CAD for USD on a net basis (in millions):

 

 

 

CAD

 

USD

 

Average Exchange Rate

 

2011 (1)

 

$

58

 

$

59

 

CAD $0.97 to US $1.00

 

2012

 

$

15

 

$

15

 

CAD $1.01 to US $1.00

 

2013

 

$

9

 

$

9

 

CAD $1.00 to US $1.00

 

 


(1)             Includes $50 million of forward exchange contracts that we entered into during July 2011.

 

Summary of Financial Impact

 

For derivatives that qualify as a cash flow hedge, changes in fair value of 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. For our interest rate swaps that qualify as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the underlying hedged item, attributable to the hedged risk, are recognized in earnings each period. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as operating cash flows in our consolidated statements of cash flows.

 

 

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A summary of the impact of our derivative activities recognized in earnings for the three and six months ended June 30, 2011 and 2010 is as follows (in millions):

 

 

 

Three Months Ended June 30, 2011

 

 

Three Months Ended June 30, 2010

 

 

 

 

 

Derivatives

 

 

 

 

 

 

Derivatives

 

 

 

 

 

Derivatives in

 

Not

 

 

 

 

Derivatives in

 

Not

 

 

 

 

 

Hedging

 

Designated

 

 

 

 

Hedging

 

Designated

 

 

 

Location of gain/(loss)

 

Relationships (1)(2)

 

as a Hedge (4)

 

Total

 

 

Relationships (1)(2)

 

as a Hedge (4)

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

(161

)

$

36

 

$

(125

)

 

$

(6

)

$

28

 

$

22

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

(6

)

1

 

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

 

(1

)

(1

)

 

(8

)

11

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

 

 

 

 

1

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

 

 

 

 

 

(3

)

(3

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income, net

 

1

 

 

1

 

 

 

1

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Gain/(Loss) on Derivatives Recognized in Net Income

 

$

(166

)

$

36

 

$

(130

)

 

$

(14

)

$

38

 

$

24

 

 

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Table of Contents

 

 

 

Six Months Ended June 30, 2011

 

 

Six Months Ended June 30, 2010

 

 

 

 

 

Derivatives

 

 

 

 

 

 

Derivatives

 

 

 

 

 

Derivatives in

 

Not

 

 

 

 

Derivatives in

 

Not

 

 

 

 

 

Hedging

 

Designated

 

 

 

 

Hedging

 

Designated

 

 

 

Location of gain/(loss)

 

Relationships (1)(2)(3)

 

as a Hedge (4)

 

Total

 

 

Relationships (1)(2)

 

as a Hedge (4)

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

(236

)

$

40

 

$

(196

)

 

$

(26

)

$

55