Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 


 

x

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

 

For the quarterly period ended September 30, 2013

 

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 October 31, 2013, there were 342,950,166 Common Units outstanding.

 

 

 



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

 

 

Page

PART I. FINANCIAL INFORMATION

 

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

 

Condensed Consolidated Balance Sheets: September 30, 2013 and December 31, 2012

3

Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2013 and 2012

4

Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2013 and 2012

5

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the nine months ended September 30, 2013

5

Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2013 and 2012

6

Condensed Consolidated Statement of Partners’ Capital: For the nine months ended September 30, 2013

7

Notes to Condensed Consolidated Financial Statements:

 

1. Organization and Basis of Presentation

8

2. Recent Accounting Pronouncements

9

3. Accounts Receivable

10

4. Dispositions

10

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

11

6. Goodwill

11

7. Debt

12

8. Net Income Per Limited Partner Unit

13

9. Partners’ Capital and Distributions

15

10. Equity Compensation Plans

16

11. Derivatives and Risk Management Activities

18

12. Commitments and Contingencies

26

13. Operating Segments

27

14. Related Party Transactions

29

15. Impairments

29

 

 

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

30

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

47

Item 4. CONTROLS AND PROCEDURES

49

 

 

PART II. OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

50

Item 1A. RISK FACTORS

50

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

50

Item 3. DEFAULTS UPON SENIOR SECURITIES

50

Item 4. MINE SAFETY DISCLOSURES

50

Item 5. OTHER INFORMATION

50

Item 6. EXHIBITS

50

SIGNATURES

51

 

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)

 

 

 

September 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

33

 

$

24

 

Trade accounts receivable and other receivables, net

 

3,562

 

3,563

 

Inventory

 

1,198

 

1,209

 

Other current assets

 

352

 

351

 

Total current assets

 

5,145

 

5,147

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

12,245

 

11,142

 

Accumulated depreciation

 

(1,638

)

(1,499

)

 

 

10,607

 

9,643

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

2,519

 

2,535

 

Linefill and base gas

 

770

 

707

 

Long-term inventory

 

218

 

274

 

Investments in unconsolidated entities

 

474

 

343

 

Other, net

 

534

 

586

 

Total assets

 

$

20,267

 

$

19,235

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

4,049

 

$

3,822

 

Short-term debt

 

619

 

1,086

 

Other current liabilities

 

343

 

275

 

Total current liabilities

 

5,011

 

5,183

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

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

 

6,710

 

6,010

 

Long-term debt under credit facilities and other

 

308

 

310

 

Other long-term liabilities and deferred credits

 

554

 

586

 

Total long-term liabilities

 

7,572

 

6,906

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (342,950,166 and 335,283,874 units outstanding, respectively)

 

6,873

 

6,388

 

General partner

 

277

 

249

 

Total partners’ capital excluding noncontrolling interests

 

7,150

 

6,637

 

Noncontrolling interests

 

534

 

509

 

Total partners’ capital

 

7,684

 

7,146

 

Total liabilities and partners’ capital

 

$

20,267

 

$

19,235

 

 

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

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(unaudited)

 

(unaudited)

 

REVENUES

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

10,386

 

$

9,048

 

$

30,542

 

$

27,367

 

Transportation segment revenues

 

179

 

150

 

517

 

458

 

Facilities segment revenues

 

138

 

156

 

558

 

533

 

Total revenues

 

10,703

 

9,354

 

31,617

 

28,358

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

9,909

 

8,524

 

28,733

 

25,855

 

Field operating costs

 

326

 

292

 

1,010

 

860

 

General and administrative expenses

 

79

 

81

 

276

 

264

 

Depreciation and amortization

 

93

 

210

 

265

 

356

 

Total costs and expenses

 

10,407

 

9,107

 

30,284

 

27,335

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

296

 

247

 

1,333

 

1,023

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

19

 

9

 

42

 

25

 

Interest expense (net of capitalized interest of $11, $9, $30 and $27, respectively)

 

(72

)

(74

)

(224

)

(214

)

Other income, net

 

3

 

4

 

2

 

6

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

246

 

186

 

1,153

 

840

 

Current income tax expense

 

(17

)

(10

)

(69

)

(32

)

Deferred income tax benefit/(expense)

 

8

 

(3

)

(10

)

(11

)

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

237

 

173

 

1,074

 

797

 

Net income attributable to noncontrolling interests

 

(6

)

(8

)

(22

)

(23

)

NET INCOME ATTRIBUTABLE TO PLAINS

 

$

231

 

$

165

 

$

1,052

 

$

774

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PLAINS:

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

133

 

$

89

 

$

764

 

$

554

 

GENERAL PARTNER

 

$

98

 

$

76

 

$

288

 

$

220

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.38

 

$

0.27

 

$

2.23

 

$

1.71

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.38

 

$

0.27

 

$

2.22

 

$

1.70

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

343

 

329

 

340

 

322

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

345

 

331

 

342

 

325

 

 

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

 

4



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

237

 

$

173

 

$

1,074

 

$

797

 

Other comprehensive income/(loss)

 

39

 

84

 

(99

)

35

 

Comprehensive income

 

276

 

257

 

975

 

832

 

Comprehensive income attributable to noncontrolling interests

 

(7

)

(5

)

(27

)

(15

)

Comprehensive income attributable to Plains

 

$

269

 

$

252

 

$

948

 

$

817

 

 

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 at December 31, 2012

 

$

(120

)

$

200

 

$

80

 

Reclassification adjustments

 

(124

)

 

(124

)

Deferred gain on cash flow hedges, net of tax

 

140

 

 

140

 

Currency translation adjustments

 

 

(115

)

(115

)

Total period activity

 

16

 

(115

)

(99

)

Balance at September 30, 2013

 

$

(104

)

$

85

 

$

(19

)

 

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)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2013

 

2012

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

1,074

 

$

797

 

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

 

 

 

 

 

Depreciation and amortization

 

265

 

356

 

Inventory valuation adjustments

 

7

 

128

 

Equity-indexed compensation expense

 

96

 

82

 

Gain on sales of linefill and base gas

 

(5

)

(17

)

Settlement of terminated interest rate and foreign currency hedging instruments

 

8

 

(23

)

(Gain)/loss on foreign currency revaluation

 

(6

)

2

 

Deferred income tax expense

 

10

 

11

 

Other

 

(7

)

(3

)

Changes in assets and liabilities, net of acquisitions

 

152

 

(453

)

Net cash provided by operating activities

 

1,594

 

880

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(28

)

(1,537

)

Additions to property, equipment and other

 

(1,217

)

(852

)

Cash received for sales of linefill and base gas

 

25

 

55

 

Cash paid for purchases of linefill and base gas

 

(61

)

(94

)

Investment in unconsolidated entities

 

(124

)

(24

)

Proceeds from sales of assets

 

62

 

21

 

Cash received upon formation of equity-method investment

 

 

55

 

Other investing activities

 

3

 

 

Net cash used in investing activities

 

(1,340

)

(2,376

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net borrowings/(repayments) under PAA senior secured hedged inventory facility (Note 7)

 

(659

)

619

 

Net borrowings/(repayments) under PAA senior unsecured revolving credit facility (Note 7)

 

(92

)

26

 

Net borrowings/(repayments) under PNG credit agreement (Note 7)

 

(32

)

54

 

Net borrowings under commercial paper program (Note 7)

 

319

 

 

Proceeds from the issuance of senior notes

 

699

 

1,247

 

Repayments of senior notes

 

 

(500

)

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

 

400

 

812

 

Net proceeds from the issuance of PNG common units

 

40

 

 

Distributions paid to common unitholders (Note 9)

 

(585

)

(502

)

Distributions paid to general partner (Note 9)

 

(270

)

(208

)

Distributions paid to noncontrolling interests

 

(37

)

(36

)

Other financing activities

 

(25

)

(11

)

Net cash (used in)/provided by financing activities

 

(242

)

1,501

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(3

)

1

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

9

 

6

 

Cash and cash equivalents, beginning of period

 

24

 

26

 

Cash and cash equivalents, end of period

 

$

33

 

$

32

 

 

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

230

 

$

207

 

Income taxes, net of amounts refunded

 

$

19

 

$

58

 

 

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 at December 31, 2012

 

335.3

 

$

6,388

 

$

249

 

$

6,637

 

$

509

 

$

7,146

 

Net income

 

 

764

 

288

 

1,052

 

22

 

1,074

 

Distributions

 

 

(585

)

(270

)

(855

)

(37

)

(892

)

Issuance of common units

 

7.2

 

392

 

8

 

400

 

 

400

 

Issuance of common units under LTIP

 

0.8

 

4

 

 

4

 

 

4

 

Units tendered by employees to satisfy tax withholding obligations

 

(0.3

)

(15

)

 

(15

)

 

(15

)

Equity-indexed compensation expense

 

 

24

 

4

 

28

 

3

 

31

 

Distribution equivalent right payments

 

 

(4

)

 

(4

)

 

(4

)

Issuance of PNG common units

 

 

8

 

 

8

 

32

 

40

 

Other

 

 

(1

)

 

(1

)

 

(1

)

Other comprehensive income/(loss)

 

 

(102

)

(2

)

(104

)

5

 

(99

)

Balance at September 30, 2013

 

343.0

 

$

6,873

 

$

277

 

$

7,150

 

$

534

 

$

7,684

 

 

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

 

Plains All American Pipeline, L.P. is a Delaware limited partnership formed in 1998. 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.  Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P., a Delaware limited partnership. On October 21, 2013, Plains GP Holdings, L.P., a Delaware limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes (“PAGP”) completed its initial public offering. As a result of the offering, PAGP currently owns an approximate 21.8% limited partner interest in Plains AAP, L.P.  The remaining limited partner interests in Plains AAP, L.P. continue to be held by the owners of PAA’s general partner entities immediately prior to PAGP’s initial public offering.  In addition to its ownership of PAA GP LLC, Plains AAP, L.P. also owns all of the incentive distribution rights in PAA. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.’s general partner.  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.

 

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 liquefied 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 operating segments.

 

Potential Acquisition of Publicly-held Common Units of PNG

 

On October 22, 2013, we announced our entry into a definitive agreement and plan of merger (the “Merger Agreement”) with PNG that provides for a merger whereby PNG will become our wholly-owned subsidiary through a unit-for-unit exchange (the “Merger”). Under the terms of the Merger Agreement, we will issue 0.445 PAA common units for each outstanding PNG common unit held by unitholders other than us, plus cash in lieu of any fractional PAA common units otherwise issuable in the Merger. There are approximately 33.0 million PNG common units owned by unitholders other than us and consummation of the transaction is expected to result in the issuance of approximately 14.7 million PAA common units. In connection with the closing of the Merger, the owners of our general partner have agreed to reduce their incentive distribution rights under our Partnership Agreement by $12 million in each of 2014 and 2015, $10 million in 2016 and $5 million per year thereafter.

 

The closing of the Merger is subject to the satisfaction of certain conditions, including the approval of the Merger and the Merger Agreement at a special meeting of the unitholders of PNG by the affirmative vote of holders of a majority of the outstanding PNG common units (including PNG common units held by us) voting as a separate class and the affirmative vote of holders of a majority of PNG’s outstanding subordinated units voting as a separate class. We own 100% of the membership interests in the general partner of PNG, 100% of the outstanding subordinated units of PNG and approximately 46% of the 61.2 million outstanding common units of PNG. Pursuant to the Merger Agreement, we have agreed to vote our common units and subordinated units in favor of the Merger. We anticipate that the Merger will close in the latter half of the fourth quarter of 2013 or the first quarter of 2014, and that the previously announced quarterly distribution of $0.3575 per PNG common unit payable to holders of record of such units on November 1, 2013 will be paid on November 14, 2013 as scheduled.

 

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

CME

=

Chicago Mercantile Exchange

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

 

8



Table of Contents

 

LIBOR

=

London Interbank Offered Rate

LLS

=

Light Louisiana Sweet

LTIP

=

Long-term incentive plan

Mcf

=

Thousand cubic feet

MLP

=

Master limited partnership

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

 

Basis of Consolidation and Presentation

 

The accompanying unaudited condensed consolidated interim financial statements and notes thereto should be read in conjunction with our 2012 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. Certain reclassifications have been made to information from previous years to conform to the current presentation. The condensed consolidated balance sheet data as of December 31, 2012 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2013 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.

 

Note 2—Recent Accounting Pronouncements

 

Other than as discussed below and in our 2012 Annual Report on Form 10-K, no new accounting pronouncements have become effective or have been issued during the nine months ended September 30, 2013 that are of significance or potential significance to us.

 

In March 2013, the FASB issued guidance regarding the release of cumulative translation adjustments into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. This guidance becomes effective beginning after December 15, 2013. We will adopt this guidance on January 1, 2014. Our adoption is not expected to have a material impact on our financial position, results of operations or cash flows.

 

In February 2013, the FASB issued guidance requiring an entity to present either in a single note or parenthetically on the face of the financial statements (i) the amount of significant items reclassified from each component of AOCI and (ii) the income statement line items affected by the reclassification. This guidance became effective for interim and annual periods beginning after December 15, 2012. We adopted this guidance during the first quarter of 2013. During the nine months ended September 30, 2013 and 2012, all reclassifications out of AOCI were related to derivative instruments. Other than requiring additional disclosure, which is included in Note 11, our adoption did not have an impact on our financial position, results of operations or cash flows.

 

In July 2012, the FASB issued guidance intended to simplify the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. We adopted this guidance on January 1, 2013. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

 

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In December 2011, the FASB issued guidance requiring disclosures of both gross and net information about recognized financial instruments and derivative instruments that are either (i) offset in accordance with the specified sections of GAAP or (ii) subject to an enforceable master netting arrangement or similar agreement. In January 2013, the FASB amended and clarified the scope of these disclosures to include only (i) derivative instruments, (ii) repurchase agreements and reverse repurchase agreements and (iii) securities lending transactions. This guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. We adopted this guidance on January 1, 2013. Other than requiring additional disclosure, which is included in Note 11, our adoption did not have an impact on our financial position, results of operations or cash flows.

 

Note 3—Accounts Receivable

 

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of crude oil, NGL, natural gas and refined products terminalling and storage services. These purchasers include, but are not limited to refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

 

To mitigate credit risk 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 September 30, 2013 and December 31, 2012, we had received approximately $122 million and $173 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, at September 30, 2013 and December 31, 2012, we had received approximately $452 million and $343 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. In addition, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis.  Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered.  We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts.  At September 30, 2013 and December 31, 2012, 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 $4 million at both September 30, 2013 and December 31, 2012.  Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

Note 4—Dispositions

 

In February 2013, we signed a definitive agreement to sell certain refined products pipeline systems and related assets included in our Transportation segment. At December 31, 2012, these assets were classified as held for sale on our condensed consolidated balance sheet (in “Other current assets”). On July 1, 2013, a portion of the transaction closed with the sale of certain of the refined products pipeline systems and related assets. The remaining assets were classified as held for sale on our condensed consolidated balance sheet as of September 30, 2013. We expect to close the balance of the transaction during the fourth quarter of 2013.

 

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Note 5—Inventory, Linefill and Base Gas and Long-term Inventory

 

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

 

 

 

September 30, 2013

 

December 31, 2012

 

 

 

 

 

Unit of

 

Carrying

 

Price/

 

 

 

Unit of

 

Carrying

 

Price/

 

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

5,624

 

barrels

 

$

535

 

$

95.13

 

9,492

 

barrels

 

$

737

 

$

77.64

 

NGL

 

13,767

 

barrels

 

539

 

$

39.15

 

9,472

 

barrels

 

388

 

$

40.96

 

Natural gas

 

29,443

 

Mcf

 

101

 

$

3.43

 

20,374

 

Mcf

 

60

 

$

2.94

 

Other

 

N/A

 

 

 

23

 

N/A

 

N/A

 

 

 

24

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,198

 

 

 

 

 

 

 

1,209

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

10,520

 

barrels

 

645

 

$

61.31

 

9,919

 

barrels

 

583

 

$

58.78

 

NGL

 

1,345

 

barrels

 

64

 

$

47.58

 

1,400

 

barrels

 

70

 

$

50.00

 

Natural gas

 

17,615

 

Mcf

 

61

 

$

3.46

 

15,755

 

Mcf

 

54

 

$

3.43

 

Linefill and base gas subtotal

 

 

 

 

 

770

 

 

 

 

 

 

 

707

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

2,134

 

barrels

 

167

 

$

78.26

 

1,962

 

barrels

 

149

 

$

75.94

 

NGL

 

1,161

 

barrels

 

51

 

$

43.93

 

3,238

 

barrels

 

125

 

$

38.60

 

Long-term inventory subtotal

 

 

 

 

 

218

 

 

 

 

 

 

 

274

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

2,186

 

 

 

 

 

 

 

$

2,190

 

 

 

 


(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.

 

At the end of each reporting period we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. We recorded a non-cash charge of approximately $7 million during the three and nine months ended September 30, 2013, primarily related to the writedown of our crude oil inventory due to declines in prices during the period. During the three and nine months ended September 30, 2012, we recorded non-cash charges of approximately $7 million and $128 million, respectively, related to the writedown of our crude oil and NGL inventory due to declines in prices during the period. The recognition of these adjustments in 2013 and 2012, which are a component of “Purchases and related costs” in our accompanying condensed consolidated statements of operations, was substantially offset by the recognition of gains on derivative instruments being utilized to hedge the future sales of our crude oil and NGL inventory. Substantially all of such gains were recorded to “Supply and Logistics segment revenues” on our condensed consolidated statements of operations.  See note 11 for discussion of our derivative and risk management activities.

 

Note 6 — Goodwill

 

The table below reflects our goodwill by segment and changes during the period indicated (in millions):

 

 

 

Transportation

 

Facilities

 

Supply and Logistics

 

Total

 

Balance at December 31, 2012

 

$

897

 

$

1,171

 

$

467

 

$

2,535

 

2013 Goodwill Related Activity:

 

 

 

 

 

 

 

 

 

Acquisitions

 

6

 

 

 

6

 

Foreign currency translation adjustments

 

(10

)

(5

)

(2

)

(17

)

Purchase price accounting adjustments and other (1) 

 

(5

)

 

 

(5

)

Balance at September 30, 2013

 

$

888

 

$

1,166

 

$

465

 

$

2,519

 

 

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(1)                          Goodwill is recorded at the acquisition date based on a preliminary fair value determination.  This preliminary goodwill balance may be adjusted when the fair value determination is finalized.

 

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

 

Note 7—Debt

 

Debt consisted of the following as of the dates indicated (in millions):

 

 

 

September 30,

 

December 31,

 

 

 

2013

 

2012

 

SHORT-TERM DEBT

 

 

 

 

 

Credit Facilities (1):

 

 

 

 

 

PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.6% at December 31, 2012 (2)

 

$

 

$

665

 

PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.4% at December 31, 2012 (2)

 

 

92

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.0% and 2.1% at September 30, 2013 and December 31, 2012, respectively (3)

 

46

 

77

 

Commercial paper notes, bearing a weighted-average interest rate of 0.25% at September 30, 2013 (2)

 

319

 

 

5.63% senior notes due December 2013 (4)

 

250

 

250

 

Other

 

4

 

2

 

Total short-term debt

 

619

 

1,086

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

Senior notes, net of unamortized discounts of $15 at both September 30, 2013 and December 31, 2012 (5)

 

6,710

 

6,010

 

Credit Facilities and Other Long-Term Debt (1):

 

 

 

 

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.0% and 2.1% at September 30, 2013 and December 31, 2012, respectively (3)

 

103

 

105

 

PNG GO Bond term loans, bearing a weighted-average interest rate of 1.5% at both September 30, 2013 and December 31, 2012

 

200

 

200

 

Other

 

5

 

5

 

Total long-term debt

 

7,018

 

6,320

 

Total debt (2) (3) (6)

 

$

7,637

 

$

7,406

 

 


(1)                          In August 2013, we renewed and extended our principal bank credit facilities. See “Credit Facilities” below for further discussion.

 

(2)                          We classify as short-term certain borrowings under our commercial paper program, PAA senior unsecured revolving credit facility and PAA senior secured hedged inventory 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.

 

(3)                         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.

 

(4)                          Our $250 million 5.63% senior notes will mature in December 2013 and are thus classified as short-term at September 30, 2013 and December 31, 2012.

 

(5)                          In August 2013, we completed the issuance of $700 million, 3.85% senior notes due 2023 at a public offering price of 99.792%. Interest payments are due on April 15 and October 15 of each year, commencing on April 15, 2014.

 

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(6)                          Our fixed-rate senior notes (including current maturities) had a face value of approximately $7.0 billion and $6.3 billion at September 30, 2013 and December 31, 2012, respectively.  We estimated the aggregate fair value of these notes as of September 30, 2013 and December 31, 2012 to be approximately $7.5 billion and $7.3 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 agreements and commercial paper program approximates fair value as interest rates reflect current market rates.  The fair value estimates for our senior notes and borrowings under our credit agreements and commercial paper program are based upon observable market data and are classified within level 2 of the fair value hierarchy.

 

Commercial Paper Program

 

In August 2013, we established a commercial paper program under which we may issue, from time to time, privately placed, unsecured commercial paper notes for up to a maximum aggregate amount outstanding at any time of $1.5 billion. Such notes are backstopped by the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility; as such, any borrowings under our commercial paper program reduce the available capacity under these facilities.

 

Credit Facilities

 

In August 2013, we amended our senior secured hedged inventory facility and senior unsecured revolving credit facility agreements to, among other things, extend the maturity dates of the facilities by two years. The facilities now mature in August 2016 and August 2018, respectively. Also in August 2013, PNG extended the maturity date of its senior unsecured revolving credit facility and GO Bond term loans by one year to August 2017.

 

Borrowings and Repayments

 

Total borrowings under our credit agreements and commercial paper program for the nine months ended September 30, 2013 and 2012 were approximately $12.7 billion and $8.5 billion, respectively. Total repayments under our credit agreements and commercial paper program were approximately $13.2 billion and $7.8 billion for the nine months ended September 30, 2013 and 2012, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

 

Letters of Credit

 

In connection with our supply and logistics activities and PNG’s natural gas storage and commercial marketing activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas.  Additionally, we issue letters of credit to support insurance programs and construction activities.  At September 30, 2013 and December 31, 2012, we had outstanding letters of credit of approximately $42 million and $24 million, respectively.

 

Note 8—Net Income Per Limited Partner Unit

 

Basic and diluted net income per limited partner unit is determined pursuant to the two-class method for Master Limited Partnerships as prescribed in the FASB guidance.  The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, common unitholders and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings.  Under this method, all earnings are allocated to our general partner, common unitholders and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective.

 

The Partnership calculates basic and diluted net income per limited partner unit by dividing net income attributable to Plains, after deducting the amount allocated to the general partner’s interest, incentive distribution rights (“IDRs”) and participating securities, by the basic and diluted weighted-average number of limited partner units outstanding during the period.  Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

 

Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method.  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 15 to our Consolidated Financial Statements included in Part IV of our 2012 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

 

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The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2013 and 2012 (in millions, except per unit data):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Basic Net Income per Limited Partner Unit

 

 

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

231

 

$

165

 

$

1,052

 

$

774

 

General partner’s incentive distribution (1)

 

(95

)

(74

)

(272

)

(208

)

General partner 2% ownership (1)

 

(3

)

(2

)

(16

)

(12

)

Net income available to limited partners

 

133

 

89

 

764

 

554

 

Undistributed earnings allocated and distributions to participating securities (1)

 

(1

)

(1

)

(5

)

(3

)

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

 

$

132

 

$

88

 

$

759

 

$

551

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

343

 

329

 

340

 

322

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.38

 

$

0.27

 

$

2.23

 

$

1.71

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income per Limited Partner Unit

 

 

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

231

 

$

165

 

$

1,052

 

$

774

 

General partner’s incentive distribution (1)

 

(95

)

(74

)

(272

)

(208

)

General partner 2% ownership (1)

 

(3

)

(2

)

(16

)

(12

)

Net income available to limited partners

 

133

 

89

 

764

 

554

 

Undistributed earnings allocated and distributions to participating securities (1)

 

(1

)

(1

)

(4

)

(3

)

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

 

$

132

 

$

88

 

$

760

 

$

551

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

343

 

329

 

340

 

322

 

Effect of dilutive securities: Weighted average LTIP units

 

2

 

2

 

2

 

3

 

Diluted weighted average number of limited partner units outstanding

 

345

 

331

 

342

 

325

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.38

 

$

0.27

 

$

2.22

 

$

1.70

 

 


(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, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

 

The terms of our partnership agreement limit the general partner’s incentive distribution to the amount of available cash, which, as defined in the partnership agreement, is net of reserves deemed appropriate.  As such, IDRs are not allocated undistributed earnings or distributions in excess of earnings in the calculation of net income per limited partner unit.  If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of the partnership agreement, basic and diluted earnings per limited partner unit as reflected in the table above would be impacted as follows:

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Basic net income per limited partner unit impact

 

$

 

$

 

$

(0.23

)

$

(0.04

)

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit impact

 

$

 

$

 

$

(0.23

)

$

(0.04

)

 

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Note 9—Partners’ Capital and Distributions

 

PAA Distributions

 

The following table details the distributions paid during or pertaining to the first nine months of 2013, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

 

 

 

 

 

Distributions Paid

 

Distributions

 

 

 

 

 

Common

 

General Partner

 

 

 

per limited

 

Date Declared

 

Date Paid or To Be Paid

 

Units

 

Incentive

 

2%

 

Total

 

partner unit

 

October 1, 2013

 

November 14, 2013 (1)

 

$

206

 

$

95

 

$

4

 

$

305

 

$

0.6000

 

July 8, 2013

 

August 14, 2013

 

$

201

 

$

91

 

$

4

 

$

296

 

$

0.5875

 

April 8, 2013

 

May 15, 2013

 

$

195

 

$

86

 

$

4

 

$

285

 

$

0.5750

 

January 7, 2013

 

February 14, 2013

 

$

189

 

$

81

 

$

4

 

$

274

 

$

0.5625

 

 


(1)                       Payable to unitholders of record at the close of business on November 1, 2013, for the period July 1, 2013 through September 30, 2013.

 

PAA Continuous Offering Program

 

In May 2013, we entered into an additional equity distribution agreement with several financial institutions pursuant to which we may offer and sell, through our sales agents, common units representing limited partner interests having an aggregate offering price of up to $750 million. During the nine months ended September 30, 2013, we issued an aggregate of approximately 7.2 million common units under our continuous offering program, generating net proceeds of approximately $400 million, including our general partner’s proportionate capital contribution, net of approximately $4 million of commissions to our sales agents.

 

LTIP Vesting

 

In connection with the settlement of vested LTIP awards (both liability-classified and equity-classified), we issued approximately 0.5 million common units during the first nine months of 2013, net of units tendered by employees for tax withholding obligations.

 

Noncontrolling Interests in Subsidiaries

 

As of September 30, 2013, noncontrolling interests in subsidiaries consisted of (i) an approximate 37% interest in PNG and (ii) a 25% interest in SLC Pipeline LLC.

 

PNG Continuous Offering Program

 

On March 18, 2013, PNG entered into an equity distribution agreement with a financial institution pursuant to which PNG may offer and sell, through its sales agent, common units representing limited partner interests having an aggregate offering price of up to $75 million. During the first nine months of 2013, PNG issued an aggregate of approximately 1.9 million common units under this agreement, generating net proceeds of approximately $40 million.

 

As a result of PNG’s common unit issuances under its continuous offering program, we recorded an increase in noncontrolling interest of approximately $32 million and an increase to our partners’ capital of approximately $8 million. These increases represent the portion of the proceeds attributable to the respective ownership interests in PNG, adjusted for the impact of the dilution of our ownership interest.

 

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The following table sets forth the impact upon net income attributable to Plains giving effect to the changes in our ownership interest in PNG, which is recognized in partners’ capital (in millions):

 

 

 

For the Three Months Ended

 

For the Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Net income attributable to Plains

 

$

231

 

$

165

 

$

1,052

 

$

774

 

Transfers to the noncontrolling interests:

 

 

 

 

 

 

 

 

 

Increase in capital from sale of PNG units

 

2

 

 

8

 

 

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

 

$

233

 

$

165

 

$

1,060

 

$

774

 

 

Noncontrolling Interests Rollforward

 

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

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2013

 

2012

 

Beginning balance

 

$

509

 

$

524

 

Net income attributable to noncontrolling interests

 

22

 

23

 

Distributions to noncontrolling interests

 

(37

)

(36

)

Equity-indexed compensation expense

 

3

 

3

 

Distribution equivalent right payments

 

 

(1

)

Issuance of PNG common units

 

32

 

 

Other comprehensive income/(loss):

 

 

 

 

 

Reclassification adjustments

 

6

 

(7

)

Net deferred loss on cash flow hedges

 

(1

)

(1

)

Ending balance

 

$

534

 

$

505

 

 

Note 10—Equity-Indexed Compensation Plans

 

We refer to the PAA and PNG LTIP Plans, Special PAA Awards and Class B Units of Plains AAP, L.P. collectively as our “Equity-indexed compensation plans.” For additional discussion of our equity-indexed compensation plans and awards, see Note 15 to our Consolidated Financial Statements included in Part IV of our 2012 Annual Report on Form 10-K.

 

Class B Units of Plains AAP, L.P. The following table contains a summary of Class B Units of Plains AAP, L.P.:

 

 

 

 

 

 

 

 

 

Grant Date

 

 

 

 

 

 

 

 

 

Fair Value of Outstanding

 

 

 

Reserved for Future

 

 

 

Outstanding Units

 

Class B Units (2)

 

 

 

Grants (1)

 

Outstanding (1)

 

Earned (1)

 

(in millions)

 

Balance at December 31, 2012

 

17,875

 

182,125

 

130,250

 

$

44

 

Granted

 

(4,500

)

4,500

 

 

7

 

Earned

 

N/A

 

N/A

 

50,125

 

N/A

 

Balance at September 30, 2013

 

13,375

 

186,625

 

180,375

 

$

51

 

 


(1)                       In connection with the initial public offering of PAGP and the recapitalization of Plains AAP, L.P. on October 21, 2013, the number of Class B Units of Plains AAP, L.P. was adjusted; as such, as of such date, the number of Class B Units of Plains AAP, L.P. reserved for future grants, outstanding and earned following this adjustment was 3,483,102 units, 48,642,833 units and 47,013,803 units, respectively.

(2)                       Of the grant date fair value, approximately $4 million was recognized as expense during the nine months ended September 30, 2013.

 

Special PAA Awards. In February 2013, we granted 143,000 Special PAA Awards to certain members of PNG’s management.  These awards are denominated in PAA common units and will vest 50% on PAA’s August 2018 distribution date and 50% on PAA’s August 2019 distribution date provided that PNG’s annualized distribution averages at least $1.48 and $1.43 per unit, respectively, for the twelve months prior to each vesting date. DERs associated with these awards will vest on the date that we pay an annualized distribution of $2.40 per unit, provided that PNG’s quarterly distribution remains at least $1.43 (annualized) per unit. Any unvested Special PAA Awards that remain outstanding on December 31, 2020 will be forfeited.

 

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

 

 

 

PAA Units (1) (2) (3)

 

PNG Units (4)

 

 

 

Units

 

Weighted Average Grant
Date
Fair Value per Unit

 

Units

 

Weighted Average Grant
Date
Fair Value per Unit

 

Outstanding at December 31, 2012

 

6.0

 

$

25.55

 

0.9

 

$

17.49

 

Granted

 

4.1

 

$

47.60

 

0.4

 

$

17.51

 

Vested

 

(1.8

)

$

24.82

 

 

$

18.88

 

Cancelled or forfeited

 

(0.3

)

$

36.32

 

 

$

13.33

 

Outstanding at September 30, 2013

 

8.0

 

$

36.74

 

1.3

 

$

17.55

 

 


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

(2)                       Amounts include Special PAA Awards.

(3)                       Approximately 0.5 million PAA common units were issued, net of approximately 0.3 million units withheld for taxes, for PAA units that vested during the nine months ended September 30, 2013. The remaining 1.0 million PAA units that vested were settled in cash.

(4)                       Less than 0.1 million PNG units vested and less than 0.1 million units were forfeited during the nine months ended September 30, 2013.

 

In February 2013, we granted 2.4 million equity-classified phantom unit awards and 1.5 million liability-classified phantom unit awards under our PAA LTIPs.  Substantially all of the equity-classified awards vest as follows: (i) one-third will vest upon the later of the August 2016 distribution date and the date we pay an annualized quarterly distribution of at least $2.35 per common unit, (ii) one-third will vest upon the later of the August 2017 distribution date and the date we pay an annualized quarterly distribution of at least $2.50 per common unit, and (iii) one-third will vest upon the later of the August 2018 distribution date and the date we pay an annualized quarterly distribution of at least $2.65 per unit.  Any of these equity-classified awards and associated DERs that have not vested as of the August 2019 distribution date will be forfeited.  Substantially all of the liability-classified awards are expected to vest on dates ranging from the August 2015 distribution date to the August 2018 distribution date and vest dependent on PAA paying annualized quarterly distributions ranging from $2.30 per common unit to $2.65 per common unit. Certain of these phantom unit awards include DERs that will vest in one-third increments upon achieving distributions of $2.35, $2.50 and $2.65 per common unit, without regard to the minimum service period.

 

Other Equity-Indexed Compensation Information.  The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Equity-indexed compensation expense

 

$

17

 

$

22

 

$

96

 

$

82

 

LTIP unit-settled vestings (1)

 

$

1

 

$

2

 

$

47

 

$

60

 

LTIP cash-settled vestings

 

$

 

$

1

 

$

61

 

$

66

 

DER cash payments

 

$

2

 

$

2

 

$

5

 

$

5

 

 


(1)                       For the nine months ended September 30, 2012, less than $1 million relates to unit-settled vestings that were settled with PNG common units.

 

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Table of Contents

 

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 our derivative 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 derivative positions and ensure that those positions are consistent with our objectives and approved strategies.  When we apply hedge accounting, 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.

 

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 to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not 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 divided 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 September 30, 2013, net derivative positions related to these activities included:

 

·                  An average of 316,500 barrels per day net long position (total of 9.8 million barrels) associated with our crude oil purchases, which was unwound ratably during October 2013 to match monthly average pricing.

 

·                  A net short spread position averaging approximately 32,800 barrels per day (total of 13.0 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through December 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.

 

·                  An average of 13,700 barrels per day (total of 1.7 million barrels) of crude oil grade spread positions through January 2014, which hedge anticipated purchases and sales of crude oil.  These derivatives are grade spreads between WTI and various other grades of crude oil including WTS, LLS and Brent. Our use of these derivatives does not expose us to outright price risk.

 

·                  An average of 2,500 barrels per day (total of 1.4 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are priced as a percentage of WTI through March 2015.

 

·                  A net long position of approximately 1.3 Bcf through April 2016 related to anticipated base gas requirements.

 

·                  A short position of approximately 29.4 Bcf through January 2014 related to anticipated sales of natural gas inventory.

 

·                  A short position of approximately 10.7 million barrels through March 2015 related to the anticipated sales of our crude oil, NGL and refined products inventory.

 

Storage Capacity Utilization — We own a significant amount 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. For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of September 30, 2013, we used derivatives to manage the risk of not utilizing approximately 2.2 million barrels per month of storage capacity through December 2013. These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil.

 

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Table of Contents

 

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit.  We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs.  As of September 30, 2013, our PLA hedges included a net short position for an average of approximately 1,700 barrels per day (total of 1.4 million barrels) through December 2015 and a long call option position of approximately 0.6 million barrels through December 2015.

 

Natural Gas Processing/NGL Fractionation — As part of our supply and logistics activities, we purchase natural gas for processing and NGL mix for fractionation, and we sell the resulting individual specification products (including ethane, propane, butane and condensate).  In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products.  As of September 30, 2013, we had a long natural gas position of approximately 16.3 Bcf through March 2015, a short propane position of approximately 2.9 million barrels through March 2015, a short butane position of approximately 0.9 million barrels through March 2015 and a short WTI position of approximately 0.3 million barrels through March 2015. In addition, we had a long power position of 0.5 million megawatt hours which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through December 2015.

 

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 September 30, 2013, AOCI includes deferred losses of approximately $76 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 loss 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 September 30, 2013 (notional amounts in millions):

 

Hedged Transaction

 

Number and Types of
Derivatives Employed

 

Notional
Amount

 

Expected
Termination Date

 

Average Fixed
Rate

 

Accounting
Treatment

 

Anticipated debt offering

 

10 forward starting swaps (30-year)

 

$

250

 

6/15/2015

 

3.60

%

Cash flow hedge

 

 

Concurrent with our August 2013 senior notes issuance, we terminated five thirty-year forward starting swaps. We received cash proceeds of approximately $11 million, of which a gain of approximately $8 million was deferred in AOCI and a gain of approximately $3 million was recognized in interest expense attributable to the ineffective portion, in connection with the termination of these swaps.

 

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 following table summarizes the terms of these swaps (notional amount in millions):

 

Hedged Transaction

 

Number and Types of
Derivatives Employed

 

Notional
Amount

 

Termination Dates

 

Average Fixed Rate

 

Accounting
Treatment

 

Floating interest rate payments associated with PNG outstanding debt

 

3 floating-to-fixed swaps

 

$

100

 

6/6/2014
8/3/2014

 

0.95

%

Cash flow hedge

 

 

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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 and forwards.  As of September 30, 2013, AOCI includes net deferred gains of approximately $1 million that relate to foreign currency derivatives that were designated for hedge accounting.

 

As of September 30, 2013, our outstanding foreign currency derivatives include derivatives we use to (i) hedge CAD-denominated interest payments on CAD-denominated intercompany notes, (ii) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (iii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

 

The following table summarizes our open forward exchange contracts as of September 30, 2013 (in millions):

 

 

 

 

 

USD

 

CAD

 

Average Exchange Rate USD
to CAD

 

Forward exchange contracts that exchange CAD for USD:

 

 

 

 

 

 

 

 

 

 

 

2013

 

$

283

 

$

292

 

$1.00 - $1.03

 

 

 

2014

 

104

 

108

 

$1.00 - $1.03

 

 

 

2015

 

9

 

9

 

$1.00 - $1.04

 

 

 

 

 

$

396

 

$

409

 

$1.00 - $1.03

 

 

 

 

 

 

 

 

 

 

 

Forward exchange contracts that exchange USD for CAD:

 

 

 

 

 

 

 

 

 

 

 

2013

 

$

281

 

$

290

 

$1.00 - $1.03

 

 

 

2014

 

104

 

108

 

$1.00 - $1.04

 

 

 

2015

 

9

 

9

 

$1.00 - $1.06

 

 

 

 

 

$

394

 

$

407

 

$1.00 - $1.03

 

 

 

 

 

 

 

 

 

 

 

Net position by currency:

 

 

 

 

 

 

 

 

 

 

 

2013

 

$

2

 

$

2

 

 

 

 

 

2014

 

 

 

 

 

 

 

2015

 

 

 

 

 

 

 

 

 

$

2

 

$

2

 

 

 

 

Summary of Financial Impact

 

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met.  For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings.  Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period.  Cash settlements associated with our derivative activities are reflected as cash flows from operating activities 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 and nine months ended September 30, 2013 and 2012 is as follows (in millions):

 

 

 

Three Months Ended September 30, 2013

 

Three Months Ended September 30, 2012

 

 

 

Derivatives in Hedging
Relationships

 

 

 

 

 

Derivatives in Hedging
Relationships

 

 

 

 

 

Location of gain/(loss)

 

Gain/(loss)
reclassified
from
AOCI into
income 
(1)

 

Other
gain/(loss)
recognized
in income

 

Derivatives
Not
Designated
as a
Hedge

 

Total

 

Gain/(loss)
reclassified
from
AOCI into
income 
(1)

 

Other
gain/(loss)
recognized
in income

 

Derivatives
Not
Designated
as a
Hedge

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

109

 

$

 

$

(91

)

$

18

 

 

$

123

 

$

 

$

(102

)

$

21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

(2

)

 

 

(2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Field operating costs

 

 

 

2

 

2

 

 

 

 

4

 

4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(2

)

3

 

 

1

 

 

(1

)

 

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Derivatives