XNYS:PAA Plains All American Pipeline LP Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended March 31, 2012

 

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

 

(I.R.S. Employer

incorporation or organization)

 

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 May 3, 2012, there were 161,318,749 Common Units outstanding.

 

 

 



Table of Contents

 

 PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

 

TABLE OF CONTENTS

 

 

Page

PART I. FINANCIAL INFORMATION

 

Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

 

Condensed Consolidated Balance Sheets: March 31, 2012 and December 31, 2011

3

Condensed Consolidated Statements of Operations: For the three months ended March 31, 2012 and 2011

4

Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2012 and 2011

5

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the three months ended March 31, 2012

5

Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2012 and 2011

6

Condensed Consolidated Statement of Partners’ Capital: For the three months ended March 31, 2012

7

Notes to Condensed Consolidated Financial Statements:

8

1. Organization and Basis of Presentation

8

2. Recent Accounting Pronouncements

9

3. Accounts Receivable

10

4. Acquisitions

10

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

11

6. Goodwill

11

7. Debt

12

8. Net Income Per Limited Partner Unit

14

9. Partners’ Capital and Distributions

14

10. Equity Compensation Plans

16

11. Derivatives and Risk Management Activities

17

12. Commitments and Contingencies

25

13. Operating Segments

26

14. Related Party Transactions

27

 

 

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

28

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

45

Item 4. CONTROLS AND PROCEDURES

46

 

 

PART II. OTHER INFORMATION

47

Item 1. LEGAL PROCEEDINGS

47

Item 1A. RISK FACTORS

47

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

47

Item 3. DEFAULTS UPON SENIOR SECURITIES

47

Item 4. MINE SAFETY DISCLOSURES

47

Item 5. OTHER INFORMATION

47

Item 6. EXHIBITS

47

SIGNATURES

48

 

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)

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

14

 

$

26

 

Trade accounts receivable and other receivables, net

 

2,902

 

3,190

 

Inventory

 

1,079

 

978

 

Other current assets

 

171

 

157

 

Total current assets

 

4,166

 

4,351

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

9,312

 

9,029

 

Accumulated depreciation

 

(1,337

)

(1,289

)

 

 

7,975

 

7,740

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

1,879

 

1,854

 

Restricted cash (Note 4)

 

1,632

 

 

Linefill and base gas

 

577

 

564

 

Long-term inventory

 

146

 

135

 

Investments in unconsolidated entities

 

192

 

191

 

Other, net

 

514

 

546

 

Total assets

 

$

17,081

 

$

15,381

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

3,489

 

$

3,599

 

Short-term debt

 

757

 

679

 

Other current liabilities

 

196

 

233

 

Total current liabilities

 

4,442

 

4,511

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discount of $15 and $13, respectively

 

5,510

 

4,262

 

Long-term debt under credit facilities and other

 

284

 

258

 

Other long-term liabilities and deferred credits

 

332

 

376

 

Total long-term liabilities

 

6,126

 

4,896

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (161,318,749 and 155,376,937 units outstanding, respectively)

 

5,779

 

5,249

 

General partner

 

218

 

201

 

Total partners’ capital excluding noncontrolling interests

 

5,997

 

5,450

 

Noncontrolling interests

 

516

 

524

 

Total partners’ capital

 

6,513

 

5,974

 

Total liabilities and partners’ capital

 

$

17,081

 

$

15,381

 

 

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

 

 

 

March 31,

 

 

 

2012

 

2011

 

 

 

(unaudited)

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Supply and Logistics segment revenues

 

$

8,877

 

$

7,435

 

Transportation segment revenues

 

150

 

141

 

Facilities segment revenues

 

191

 

118

 

Total revenues

 

9,218

 

7,694

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

Purchases and related costs

 

8,502

 

7,079

 

Field operating costs

 

249

 

197

 

General and administrative expenses

 

94

 

70

 

Depreciation and amortization

 

60

 

63

 

Total costs and expenses

 

8,905

 

7,409

 

 

 

 

 

 

 

OPERATING INCOME

 

313

 

285

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

Equity earnings in unconsolidated entities

 

7

 

 

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

 

(65

)

(65

)

Other income/(expense), net

 

2

 

(22

)

 

 

 

 

 

 

INCOME BEFORE TAX

 

257

 

198

 

Current income tax expense

 

(17

)

(11

)

Deferred income tax expense

 

(3

)

(2

)

 

 

 

 

 

 

NET INCOME

 

237

 

185

 

Net income attributable to noncontrolling interests

 

(7

)

(3

)

NET INCOME ATTRIBUTABLE TO PLAINS

 

$

230

 

$

182

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PLAINS:

 

 

 

 

 

LIMITED PARTNERS

 

$

162

 

$

129

 

GENERAL PARTNER

 

$

68

 

$

53

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

1.03

 

$

0.90

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

1.02

 

$

0.90

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

157

 

143

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

158

 

144

 

 

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 COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

 

 

(unaudited)

 

Net income

 

$

237

 

$

185

 

Other comprehensive income/(loss)

 

59

 

(29

)

Comprehensive income

 

296

 

156

 

Less: Comprehensive income attributable to noncontrolling interests

 

(3

)

(3

)

Comprehensive income attributable to Plains

 

$

293

 

$

153

 

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

 

 

Derivative

 

Translation

 

 

 

 

 

Instruments

 

Adjustments

 

Total

 

 

 

(unaudited)

 

Balance, December 31, 2011

 

$

(102

)

$

156

 

$

54

 

Reclassification adjustments

 

(52

)

 

(52

)

Deferred gain on cash flow hedges, net of tax

 

76

 

 

76

 

Currency translation adjustment

 

 

35

 

35

 

Total period activity

 

24

 

35

 

59

 

Balance, March 31, 2012

 

$

(78

)

$

191

 

$

113

 

 

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 STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

237

 

$

185

 

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

 

 

 

 

 

Depreciation and amortization

 

60

 

63

 

Equity compensation expense

 

39

 

20

 

Gain on sales of linefill and base gas

 

(12

)

(13

)

Net cash received/(paid) for terminated interest rate or foreign currency
hedging instruments

 

(23

)

12

 

Other

 

(4

)

3

 

Changes in assets and liabilities, net of acquisitions

 

20

 

384

 

Net cash provided by operating activities

 

317

 

654

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(21

)

(756

)

Change in restricted cash

 

(1,632

)

18

 

Additions to property and equipment

 

(263

)

(121

)

Proceeds from sales of assets

 

13

 

 

Net cash received for sales and purchases of linefill and base gas

 

13

 

19

 

Other investing activities

 

 

(2

)

Net cash used in investing activities

 

(1,890

)

(842

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

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

 

184

 

(654

)

Net repayments on PAA’s hedged inventory facility

 

(75

)

(200

)

Net repayments on PNG’s credit agreements

 

(5

)

(52

)

Proceeds from the issuance of senior notes

 

1,247

 

597

 

Repayments of senior notes

 

 

(200

)

Net proceeds from the issuance of common units (Note 9)

 

455

 

503

 

Cash received for sale of noncontrolling interest in a subsidiary

 

 

370

 

Distributions paid to common unitholders (Note 9)

 

(159

)

(135

)

Distributions paid to general partner (Note 9)

 

(66

)

(49

)

Distributions to noncontrolling interests

 

(12

)

(5

)

Other financing activities

 

(9

)

(4

)

Net cash provided by financing activities

 

1,560

 

171

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

1

 

 

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(12

)

(17

)

Cash and cash equivalents, beginning of period

 

26

 

36

 

Cash and cash equivalents, end of period

 

$

14

 

$

19

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

78

 

$

71

 

 

 

 

 

 

 

Cash paid for income taxes, net of amounts refunded

 

$

28

 

$

 

 

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

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, 2011

 

155

 

$

5,249

 

$

201

 

$

5,450

 

$

524

 

$

5,974

 

Net income

 

 

162

 

68

 

230

 

7

 

237

 

Distributions

 

 

(159

)

(66

)

(225

)

(12

)

(237

)

Issuance of common units

 

6

 

446

 

9

 

455

 

 

455

 

Issuance of common units under LTIP

 

 

16

 

 

16

 

 

16

 

Equity compensation expense

 

 

3

 

5

 

8

 

1

 

9

 

Other comprehensive income/(loss)

 

 

62

 

1

 

63

 

(4

)

59

 

Balance, March 31, 2012

 

161

 

$

5,779

 

$

218

 

$

5,997

 

$

516

 

$

6,513

 

 

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

 

7



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 and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids (“NGL”).  The term NGL includes ethane and natural gasoline products as well as propane and butane, products which are also commonly referred to as liquid petroleum gas (“LPG”).  When used in this document, NGL refers to all NGL products including LPG. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also own and operate natural gas storage facilities. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 13 for further discussion 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

 

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

GAAP

 

=

 

Generally accepted accounting principles in the United States

ICE

 

=

 

IntercontinentalExchange

LIBOR

 

=

 

London Interbank Offered Rate

LLS

 

=

 

Light Louisiana Sweet

LTIP

 

=

 

Long-term incentive plan

Mcf

 

=

 

Thousand cubic feet

MLP

 

=

 

Master limited partnership

MQD

 

=

 

Minimum quarterly distribution

NGL

 

=

 

Natural gas liquids including ethane, natural gasoline products, propane and butane

NPNS

 

=

 

Normal purchases and normal sales

NYMEX

 

=

 

New York Mercantile Exchange

NYSE

 

=

 

New York Stock Exchange

PLA

 

=

 

Pipeline loss allowance

PNG

 

=

 

PAA Natural Gas Storage, L.P.

SEC

 

=

 

Securities and Exchange Commission

USD

 

=

 

United States dollar

WTI

 

=

 

West Texas Intermediate

WTS

 

=

 

West Texas Sour

 

8



Table of Contents

 

Basis of Consolidation and Presentation

 

The accompanying unaudited condensed consolidated interim financial statements and notes thereto should be read in conjunction with our 2011 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth 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. The condensed balance sheet data as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2012 should not be taken as indicative of results to be expected for the entire year.

 

Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

 

Revision of Prior Period Financial Statements

 

Limited Partner and General Partner Income Allocation

 

During 2011, we identified an error in the manner in which we allocate net income to our limited partners and general partner.  Previously, we calculated net income available to limited partners based on the distribution paid during the period by first allocating the incentive distribution paid during the period to the general partner and then allocating the remaining net income based on ownership interests (98% limited partner and 2% general partner).  We have revised this allocation to utilize the distributions pertaining to the period, which are paid in the subsequent period.  This revision does not impact net income, net income attributable to Plains, net income per limited partner unit, total partners’ capital or cash flows.  We have determined that the impact of this error is not material to the previously issued financial statements.  We have presented these changes retrospectively in the condensed consolidated statement of operations, which resulted in the following changes (in millions):

 

Three Months Ended March 31, 2011

 

As
Previously
Reported

 

As
Revised

 

Net Income Attributable to Plains:

 

 

 

 

 

Limited Partners

 

$

133

 

$

129

 

General Partner

 

49

 

53

 

 

 

$

182

 

$

182

 

 

Note 2—Recent Accounting Pronouncements

 

Other than as discussed below and in our 2011 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the three months ended March 31, 2012 that are of significance or potential significance to us.

 

In September 2011, the FASB issued guidance with the purpose of simplifying the goodwill impairment test by permitting entities to perform a qualitative assessment to determine whether further impairment testing is necessary. If qualitative factors indicate that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, an entity need not perform the two-step goodwill impairment test. This guidance became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

 

In June 2011, the FASB issued guidance regarding the presentation of other comprehensive income, which was later amended in December 2011, with the purpose of increasing the prominence of other comprehensive income in financial statements. This guidance, as amended, requires entities to present comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted the guidance, as amended, on January 1, 2012. Since this guidance only impacts the presentation of comprehensive income and does not change the composition or calculation of such financial information, adoption did not have a material impact on our financial position, results of operations or cash flows.

 

In May 2011, the FASB issued guidance to amend certain fair value measurement and disclosure requirements in an effort to improve consistency with international reporting standards. The amendments generally clarify that the concepts of highest and best use and valuation premise in fair value measurement are relevant only when measuring the fair value of non-financial assets and are not relevant when measuring the fair value of financial assets or of liabilities.  In addition, the guidance expanded disclosure requirements associated with (i) unobservable inputs for Level 3 fair value measurements and (ii) items that are not measured at fair value in the financial statements, but for which fair value is required to be disclosed. This guidance became effective prospectively for

 

9



Table of Contents

 

interim and annual reporting periods beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Other than requiring additional disclosure, which is included in Note 7, our adoption did not have a material impact on our financial position, results of operations or cash flows.

 

Note 3—Accounts Receivable

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2012 and December 31, 2011, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled approximately $5 million at both March 31, 2012 and December 31, 2011. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

To mitigate credit risks related to our accounts receivable, we have in place a rigorous credit review process.  We closely monitor market conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, parental guarantees or advance cash payments. At March 31, 2012 and December 31, 2011, we had received approximately $177 million and $186 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 portion of our transactions and also serve to mitigate credit risk.

 

Note 4—Acquisitions

 

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

 

Acquisition Closed Subsequent to March 31, 2012

 

BP NGL Acquisition. On April 1, 2012, we acquired all of the outstanding shares of BP Canada Energy Company, a wholly owned subsidiary of BP Corporation North America Inc. (“BP North America”).  Total consideration for the acquisition, which was based on an October 1, 2011 effective date, was approximately $1.67 billion, subject to working capital and other adjustments. A cash deposit of $50 million was paid upon signing, and the balance plus 2% interest from October 1, 2011 was paid in cash upon closing. As of March 31, 2012, we had approximately $1.63 billion in restricted cash held by an escrow agent in contemplation of closing this acquisition.

 

Upon completion of this acquisition, we became the indirect owner of all of BP North America’s Canadian-based NGL business and certain of BP North America’s NGL assets located in the upper-Midwest United States (collectively the “BP NGL Assets”). The BP NGL Assets acquired include varying ownership interests and contractual rights relating to approximately 2,600 miles of NGL pipelines; approximately 20 million barrels of NGL storage capacity; seven fractionation plants with an aggregate net capacity of approximately 232,000 barrels per day; four straddle plants and two field gas processing plants with an aggregate net capacity of approximately six Bcf per day; and long-term and seasonal NGL inventories of approximately 8 million barrels upon closing. Certain of these pipelines and storage assets are currently inactive. The acquired business also includes various third-party supply contracts at other field gas processing plants and a supply contract relating to a third-party owned straddle plant with throughput capacity of 2.5 Bcf per day, shipping arrangements on third-party NGL pipelines and long-term leases on 720 rail cars used to move product among various locations. We have also entered into an Integrated Supply and Trading Agreement, pursuant to which an affiliate of BP North America will, for a period of two years following the closing of the acquisition, continue to provide sourcing services for gas supply to feed certain of the straddle plants acquired as a result of the acquisition.

 

Other Acquisitions

 

During the three months ended March 31, 2012 we completed two acquisitions for an aggregate consideration of approximately $21 million. The assets acquired primarily included trailers that are utilized in our transportation segment, and terminal facilities included in our facilities segment. We recognized goodwill of approximately $10 million related to these acquisitions.

 

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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):

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Unit of

 

Total

 

Price/

 

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

8,464

 

barrels

 

$

821

 

$

97.00

 

5,361

 

barrels

 

$

483

 

$

90.10

 

NGL

 

3,829

 

barrels

 

216

 

$

56.41

 

6,885

 

barrels

 

438

 

$

63.62

 

Natural gas (2)

 

14,453

 

Mcf

 

33

 

$

2.28

 

16,170

 

Mcf

 

51

 

$

3.15

 

Other

 

N/A

 

 

 

9

 

N/A

 

N/A

 

 

 

6

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,079

 

 

 

 

 

 

 

978

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,410

 

barrels

 

526

 

$

55.90

 

9,366

 

barrels

 

514

 

$

54.88

 

Natural gas (2)

 

14,105

 

Mcf

 

49

 

$

3.47

 

14,105

 

Mcf

 

48

 

$

3.40

 

NGL

 

31

 

barrels

 

2

 

$

64.52

 

31

 

barrels

 

2

 

$

64.52

 

Linefill and base gas subtotal

 

 

 

 

 

577

 

 

 

 

 

 

 

564

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,848

 

barrels

 

138

 

$

74.68

 

1,714

 

barrels

 

127

 

$

74.10

 

NGL

 

150

 

barrels

 

8

 

$

53.33

 

150

 

barrels

 

8

 

$

53.33

 

Long-term inventory subtotal

 

 

 

 

 

146

 

 

 

 

 

 

 

135

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

1,802

 

 

 

 

 

 

 

$

1,677

 

 

 

 


(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, 2011

 

$

818

 

$

609

 

$

427

 

$

1,854

 

2012 Goodwill Related Activity:

 

 

 

 

 

 

 

 

 

Acquisitions (2)

 

10

 

 

 

10

 

Foreign currency translation adjustments

 

4

 

 

1

 

5

 

Purchase price accounting adjustments and other (2)

 

10

 

 

 

10

 

Balance, March 31, 2012

 

$

842

 

$

609

 

$

428

 

$

1,879

 

 


(1)                         As of March 31, 2012, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

 

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

 

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Note 7—Debt

 

Debt consisted of the following (in millions):

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

SHORT-TERM DEBT

 

 

 

 

 

Credit Facilities:

 

 

 

 

 

Senior secured hedged inventory facility bearing a weighted-average interest rate of 1.5% at December 31, 2011

 

$

 

$

75

 

PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 1.5% and 1.6% at March 31, 2012 and December 31, 2011, respectively (1)

 

217

 

32

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both March 31, 2012 and December 31, 2011 (2)

 

37

 

68

 

4.25% senior notes due September 2012 (3)

 

500

 

500

 

Other

 

3

 

4

 

Total short-term debt

 

757

 

679

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

Senior Notes:

 

 

 

 

 

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

 

600

 

600

 

3.65% senior notes due June 2022 (4)

 

750

 

 

6.70% senior notes due May 2036

 

250

 

250

 

6.65% senior notes due January 2037

 

600

 

600

 

5.15% senior notes due June 2042 (4)

 

500

 

 

Unamortized discounts

 

(15

)

(13

)

Senior notes, net of unamortized discounts

 

5,510

 

4,262

 

Credit Facilities and Other:

 

 

 

 

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both March 31, 2012 and December 31, 2011 (2)

 

79

 

54

 

PNG GO Zone term loans, bearing a weighted-average interest rate of 1.5% at both March 31, 2012 and December 31, 2011

 

200

 

200

 

Other

 

5

 

4

 

Total long-term debt

 

5,794

 

4,520

 

Total debt (1) (2) (5)

 

$

6,551

 

$

5,199

 

 


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

 

(2)                         PNG classifies as short-term debt any borrowings under the PNG senior unsecured revolving credit facility that have been designated as working capital borrowings and must be repaid within one year. Such borrowings are primarily related to a portion of PNG’s hedged natural gas inventory.

 

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(3)                         Our $500 million 4.25% senior notes will mature in September 2012. The proceeds from these notes are being used to supplement capital available from our hedged inventory facility, to fund working capital needs associated with base levels of waterborne cargos and for seasonal NGL inventory requirements. After these notes mature, we intend to use our credit facilities to finance hedged inventory. Concurrent with the issuance of these senior notes in July 2009, we entered into interest rate swaps. See Note 6 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for further discussion of our interest rate swaps.

 

(4)                         In March 2012, we completed the issuance of $750 million, 3.65% senior notes due 2022 and $500 million, 5.15% senior notes due 2042. The senior notes were sold at 99.823% and 99.755% of face value, respectively. Interest payments are due on June 1 and December 1 each year, beginning on December 1, 2012. We used the net proceeds from these offerings to fund a portion of the consideration for the BP NGL Acquisition and for general partnership purposes. See Note 4 for more information regarding this acquisition.

 

(5)                         Our fixed-rate senior notes had a face value of approximately $6.0 billion and $4.8 billion as of March 31, 2012 and December 31, 2011, respectively. We estimated the aggregate fair value of these notes as of March 31, 2012 and December 31, 2011 to be approximately $6.7 billion and $5.4 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these 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. The fair value estimates for both our senior notes and credit facilities are based upon observable market data and are classified within Level 2 of the fair value hierarchy.

 

Credit Facilities

 

PAA senior unsecured 364-day revolving credit agreement. In December 2011, we entered into a 364-day credit facility agreement with a borrowing capacity of $1.2 billion. Pursuant to its terms, we had the option to activate the facility at any time over a six-month period. In March 2012, we elected to terminate this credit agreement.

 

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 March 31, 2012 and December 31, 2011, we had outstanding letters of credit of approximately $42 million and $33 million, respectively.

 

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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 months ended March 31, 2012 and 2011 (amounts in millions, except per unit data):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Numerator for basic and diluted earnings per limited partner unit (1):

 

 

 

 

 

Net income attributable to Plains

 

$

230

 

$

182

 

Less: General partner’s incentive distribution

 

(65

)

(50

)

Less: General partner 2% ownership

 

(3

)

(3

)

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

 

$

162

 

$

129

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

157

 

143

 

Effect of dilutive securities:

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

158

 

144

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

1.03

 

$

0.90

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

1.02

 

$

0.90

 

 


(1)                         We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income.  After adjusting for the appropriate period’s distributions, 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.

 

(2)                         Our LTIP awards 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. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our LTIP awards.

 

Note 9—Partners’ Capital and Distributions

 

PAA Distributions

 

The following table details the distributions paid during or pertaining to the first three months of 2012, 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

 

April 10, 2012

 

May 15, 2012 (1)

 

$

169

 

$

65

 

$

3

 

$

237

 

$

1.0450

 

January 10, 2012

 

February 14, 2012

 

$

159

 

$

63

 

$

3

 

$

225

 

$

1.0250

 

 


(1)                         Payable to unitholders of record at the close of business on May 4, 2012, for the period January 1, 2012 through March 31, 2012.

 

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In order to enhance our distribution coverage ratio and liquidity following a significant acquisition, our general partner has, from time to time, agreed to reduce the amounts due to it as incentive distributions. As such, beginning with the first distribution declared and paid after closing the BP NGL Acquisition, which occurred on April 1, 2012, our general partner agreed to reduce the amount of its incentive distributions by $15 million per year for two years and $10 million per year thereafter. The first incentive distribution reduction related to this acquisition of approximately $4 million will be applied to the May 2012 distribution. See Note 4 for further discussion of the BP NGL Acquisition.

 

PAA Equity Offerings

 

During the three months ended March 31, 2012, we completed an equity offering of our common units as shown in the table below (in millions, except unit and per unit data):

 

 

 

 

 

Gross

 

Proceeds

 

General Partner

 

 

 

Net

 

Date

 

Units Issued

 

Unit Price

 

from Sale

 

Contribution

 

Costs

 

Proceeds

 

March 2012 (1)

 

5,750,000

 

$

80.03

 

$

460

 

$

9

 

$

(14

)

$

455

 

 


(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 fund a portion of the BP NGL acquisition, to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

 

LTIP Vesting

 

In connection with the settlement of vested LTIP awards, we issued 191,812 common units during the three months ended March 31, 2012 with a fair value of approximately $16 million.

 

Noncontrolling Interests in Subsidiaries

 

As of March 31, 2012, noncontrolling interests in subsidiaries consisted of the following: (i) an approximate 36 % interest in PNG and (ii) a 25% interest in SLC Pipeline LLC.

 

Modification of Conversion of PNG Subordinated Units

 

In February 2012, PNG modified the terms of the first three tranches of the PNG Series B subordinated units held by PAA. The Series B subordinated units do not participate in quarterly distributions. Instead, the Series B subordinated units convert into Series A subordinated units or common units in five distinct tranches upon the achievement of defined benchmarks tied to the amount of capacity in service at Pine Prairie and increases in PNG’s quarterly distributions. The modification increased the quarterly distribution benchmark for Tranche 1, 2 and 3 from annualized levels of $1.44 per unit, $1.53 per unit and $1.63 per unit, respectively, to an annualized level of $1.71 per unit. The following table presents the operational and financial benchmarks, as modified, for conversion of the Series B subordinated units into Series A subordinated units for each tranche (units in millions):

 

 

 

Series B Subordinated Units to Convert into
Series A Subordinated Units

 

Working Gas Storage Capacity (Bcf)

 

Annualized
Distribution Level 
(1)

 

Tranche 1

 

2.6

 

29.6

 

$

1.71

 

Tranche 2

 

2.8

 

35.6

 

$

1.71

 

Tranche 3

 

2.1

 

41.6

 

$

1.71

 

Tranche 4

 

3.0

 

48.0

 

$

1.71

 

Tranche 5

 

3.0

 

48.0

 

$

1.80

 

 


(1)                         For satisfaction of this benchmark, PNG must, for two consecutive quarters, (i) maintain distributable cash flow sufficient to pay a quarterly distribution of at least the annualized distribution benchmark on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and (ii) distribute available cash of at least the annualized distribution benchmark on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights. See Note 5 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our Series B subordinated units.

 

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Noncontrolling Interests Rollforward

 

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

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

Beginning balance

 

$

524

 

$

231

 

Sale of noncontrolling interests in a subsidiary

 

 

306

 

Net income attributable to noncontrolling interests

 

7

 

3

 

Distributions to noncontrolling interests

 

(12

)

(5

)

Equity compensation expense

 

1

 

1

 

Other comprehensive income/(loss):

 

 

 

 

 

Reclassification adjustments

 

(6

)

 

Deferred gain/(loss) on cash flow hedges, net

 

2

 

 

Ending Balance

 

$

516

 

$

536

 

 

Note 10—Equity Compensation Plans

 

For a complete discussion of our equity compensation awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K.

 

PNG Long-term Incentive Plan Award Modification.  In February 2012, the Board of Directors of PNG’s general partner approved the modification of certain awards previously granted under the PNG Plan.  As a result of the modification, approximately 232,500 equity-classified phantom unit awards will now vest in the following manner: (i) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in February 2012, will vest upon the date PNG pays an annualized distribution of at least $1.45, (ii) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in May 2013, will vest upon the date PNG pays an annualized distribution of at least $1.50 and (iii) the remainder, with distribution equivalent rights also modified to begin payment in May 2014, will vest upon the date PNG pays an annualized distribution of at least $1.55.  Fifty percent of any awards that have not vested as of the November 2016 distribution date will vest at that time and the remainder will expire.  Additionally, 232,500 of equity-classified phantom unit awards with vesting terms originally tied to the conversion of PNG’s Series A and Series B subordinated units were modified such that all these awards will now fully vest upon conversion of the Series A subordinated units to common units.  Distribution equivalent rights were also granted with respect to these awards beginning in February 2012.  There was no financial impact at the time of the modification; however, we anticipate that we will recognize additional equity compensation expense in the future as a result of the modification.

 

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

 

 

 

PAA Units (1)

 

 

PNG Units (2)(3)(4)

 

 

 

Units

 

Weighted Average Grant
Date
Fair Value per Unit

 

 

Units

 

Weighted Average Grant
Date
Fair Value per Unit

 

Outstanding, December 31, 2011

 

4.0

 

$

43.53

 

 

0.8

 

$

20.55

 

Granted

 

0.7

 

$

65.63

 

 

0.1

 

$

15.05

 

Vested (5)

 

(0.8

)

$

37.85

 

 

 

$

 

Outstanding, March 31, 2012

 

3.9

 

$

48.65

 

 

0.9

 

$

17.97

 

 


(1)                         Amounts do not include Class B units of Plains AAP, L.P.

(2)                         Amounts do not include Class B units of PNGS GP LLC.

(3)                         Amounts include PNG Transaction Grants.

(4)                         Weighted average grant date fair value per unit for PNG Units outstanding at March 31, 2012, is impacted by the modification of PNG awards during the first quarter of 2012 as discussed above.

(5)                         Approximately 0.2 million PAA units were issued, net of approximately 0.1 million units withheld for taxes, during the three months ended March 31, 2012. The remaining 0.5 million units that vested were settled in cash.

 

Class B Units of Plains AAP, L.P. At March 31, 2012 and December 31, 2011, 183,500 AAP LP Class B units were outstanding. As of March 31, 2012, approximately 104,313 of the Class B units outstanding had been earned, 24,250 of which became earned during the three months ended March 31, 2012. A total of 16,500 AAP LP Class B units are reserved for future issuances.

 

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

 

 

 

March 31,

 

 

 

2012

 

2011

 

Equity compensation expense

 

$

39

 

$

20

 

LTIP unit-settled vestings

 

$

24

 

$

 

LTIP cash-settled vestings

 

$

36

 

$

 

DER cash payments

 

$

2

 

$

1

 

 

Note 11—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 hydrocarbon commodity (referred to herein as “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 for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.

 

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Table of Contents

 

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 inventory 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 March 31, 2012, net derivative positions related to these activities included:

 

·                  An approximate 217,100 barrels per day net long position (total of 6.5 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2012 to match monthly average pricing.

 

·                  A net short spread position averaging approximately 21,400 barrels per day (total of 19.6 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through November 2014.  These derivatives are time spreads consisting of offsetting purchases and sales between two different months. Our use of these derivatives does not expose us to outright price risk.

 

·                  Approximately 9,000 barrels per day on average (total of 5.8 million barrels) of WTS/WTI crude oil basis swaps through December 2013, which hedge anticipated sales of crude oil (WTI).  These derivatives are grade spreads between two different grades of crude oil. Our use of these derivatives does not expose us to outright price risk.

 

·                  Approximately 10,500 barrels per day on average (total of 2.6 million barrels) of LLS/WTI crude oil basis swaps from May 2012 through December 2012, which hedge anticipated sales of crude oil.  These derivatives are grade spreads between two different grades of crude oil. Our use of these derivatives does not expose us to outright price risk.

 

·                  An average of 16,200 barrels per day (total of 1.5 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are based on a percentage of WTI through June 2012.

 

·                  A short swap position of approximately 21.9 Bcf through December 2012 related to anticipated sales of natural gas.

 

Inventory Storage — We own approximately 78 million barrels of crude oil, NGL 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. From time to time, we elect to purchase and store crude oil, NGL 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 March 31, 2012, we had a net short open derivative volume of approximately 7.5 million barrels hedging our inventory or anticipated inventory storage. These positions are a combination of futures, swaps and option contracts.

 

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of March 31, 2012, our PLA hedges included (i) a net short position consisting of crude oil futures and swaps for an average of approximately 1,500 barrels per day (total of 2.1 million barrels) through December 2015, (ii) a long put option position of approximately 0.2 million barrels through December 2012 and (iii) a long call option position of approximately 0.6 million barrels through December 2015.

 

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Table of Contents

 

Base Gas Management — Our gas storage facilities require minimum levels of base gas to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of March 31, 2012, we had a long swap position of approximately 3.5 Bcf through August 2014 related to anticipated base gas purchases.

 

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 March 31, 2012, AOCI includes deferred losses of approximately $82 million that relate to open and terminated interest rate derivatives 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 terms of the hedged debt instruments.

 

We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2015. The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2012 (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

 

6 forward starting swaps (30-year)

 

$

250

 

6/17/2013

 

4.24

%

Cash flow hedge

 

Anticipated debt offering

 

2 forward starting swaps (30-year)

 

$

50

 

6/16/2014

 

3.94

%

Cash flow hedge

 

Anticipated debt offering

 

10 forward starting swaps (30-year)

 

$

250

 

6/15/2015

 

3.60

%

Cash flow hedge

 

 

During June 2011 and August 2011, PNG entered into three interest rate swaps to fix the interest rate on a portion of PNG’s outstanding debt. The swaps have an aggregate notional amount of $100 million with an average fixed rate of 0.95%. Two of these swaps terminate in June 2014 and the remaining swap terminates in August 2014. These swaps are designated as cash flow hedges.

 

Concurrent with our March 2012 senior note issuances, we terminated four ten-year forward starting interest rate swaps. These swaps had an aggregate notional amount of $200 million and an average fixed rate of 3.46%. We paid out cash of approximately $24 million associated with the termination of the swaps.

 

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

 

During July 2009, concurrent with our senior notes issuance, 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 terminated in September 2011, and two of the swaps will terminate in September 2012. The swaps that terminate in 2012 are designated as fair value hedges.

 

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Table of Contents

 

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 March 31, 2012, AOCI includes net deferred gains of approximately $9 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 CAD-denominated intercompany notes as a result of changes in the exchange rate.

 

As of March 31, 2012, 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

 

2012

 

$

11

 

$

11

 

CAD $1.01 to USD $1.00

 

2013

 

$

9

 

$

9

 

CAD $1.00 to USD $1.00

 

 

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 condensed consolidated statements of cash flows.

 

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Table of Contents

 

A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2012 and 2011 is as follows (in millions):

 

 

 

Three Months Ended March 31, 2012

 

Three Months Ended March 31, 2011

 

 

 

 

 

Derivatives

 

 

 

 

 

Derivatives

 

 

 

 

 

Derivatives in

 

Not

 

 

 

Derivatives in

 

Not

 

 

 

 

 

Hedging

 

Designated

 

 

 

Hedging

 

Designated

 

 

 

Location of gain/(loss)

 

Relationships (1)(2)(3)(5)

 

as a Hedge (4)

 

Total

 

Relationships (1)(2)(3)

 

as a Hedge (4)

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

34

 

$

(38

)

$

(4

)

 

$

(75

)

$

4

 

$

(71

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation segment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

12

 

 

12

 

 

(1

)

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

4

 

1

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Field operating costs

 

 

2

 

2

 

 

 

1

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(1

)

 

(1

)

 

1

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

 

1

 

1

 

 

 

3

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income/(expense), net

 

1

 

 

1

 

 

1

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

50

 

$

(34

)

$

16

 

 

$

(74

)

$

8

 

$

(66

)

 


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

(2)             Amounts include losses of approximately $3 million and approximately $8 million for the three months ended March 31, 2012 and 2011, respectively, that represent the ineffective portion of our cash flow hedges. These amounts relate to commodity and interest rate derivatives.

(3)             Interest expense includes a net gain of approximately $1 million for both the three months ended March 31, 2012 and 2011, respectively, associated with outstanding interest rate swaps, which are designated as a fair value hedge.

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

(5)             Includes unrealized gains of approximately $4 million reclassified from AOCI to earnings during the period to offset a lower of cost or market adjustment relating to the carrying value of PNG’s inventory.

 

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Table of Contents

 

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of March 31, 2012 (in millions):

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

Balance Sheet

 

 

 

 

Balance Sheet

 

 

 

 

 

Location

 

Fair Value

 

 

Location

 

Fair Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

87

 

 

Other current assets

 

$

(54

)

 

 

Other long-term assets

 

7

 

 

Other long-term assets

 

(1

)

 

 

Other long-term liabilities

 

3

 

 

Other long-term liabilities

 

(3

)

Interest rate derivatives

 

Other current assets

 

1

 

 

Other current liabilities

 

(1

)

 

 

Other long-term assets

 

2

 

 

Other long-term liabilities

 

(65

)

Foreign currency derivatives

 

Other current assets

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total derivatives designated as hedging instruments

 

 

 

$

101

 

 

 

 

$

(124

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

44

 

 

Other current assets

 

$

(39

)

 

 

Other long-term liabilities

 

1

 

 

Other long-term assets

 

(6

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives not designated as hedging  instruments

 

 

 

$

45

 

 

 

 

$

(45

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

146

 

 

 

 

$

(169

)

 

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of December 31, 2011 (in millions):

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

Balance Sheet

 

 

 

 

Balance Sheet

 

 

 

 

 

Location

 

Fair Value

 

 

Location

 

Fair Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

72

 

 

Other current assets

 

$

(47

)

 

 

Other long-term assets

 

20

 

 

Other long-term assets

 

(2

)

Interest rate derivatives

 

Other current assets

 

1

 

 

Other current liabilities

 

(24

)

 

 

 

 

 

 

 

Other long-term liabilities

 

(114

)

Foreign currency derivatives

 

Other current assets

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total derivatives designated as hedging instruments

 

 

 

$

94