Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended June 30, 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 July 31, 2013, there were 342,735,916 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:

3

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

3

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

4

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

5

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

5

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

6

Condensed Consolidated Statement of Partners’ Capital: For the six months ended June 30, 2013

7

Notes to Condensed Consolidated Financial Statements:

8

1. Organization and Basis of Presentation

8

2. Recent Accounting Pronouncements

9

3. Accounts Receivable

9

4. Acquisitions and Dispositions

10

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

10

6. Goodwill

11

7. Debt

11

8. Net Income Per Limited Partner Unit

12

9. Partners’ Capital and Distributions

14

10. Equity Compensation Plans

15

11. Derivatives and Risk Management Activities

17

12. Commitments and Contingencies

25

13. Operating Segments

26

14. Related Party Transactions

28

 

 

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

29

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

45

Item 4. CONTROLS AND PROCEDURES

46

 

 

PART II. OTHER INFORMATION

 

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)

 

 

 

June 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

16

 

$

24

 

Trade accounts receivable and other receivables, net

 

3,503

 

3,563

 

Inventory

 

892

 

1,209

 

Other current assets

 

430

 

351

 

Total current assets

 

4,841

 

5,147

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

11,762

 

11,142

 

Accumulated depreciation

 

(1,581

)

(1,499

)

 

 

10,181

 

9,643

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

2,503

 

2,535

 

Linefill and base gas

 

707

 

707

 

Long-term inventory

 

207

 

274

 

Investments in unconsolidated entities

 

442

 

343

 

Other, net

 

543

 

586

 

Total assets

 

$

19,424

 

$

19,235

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

3,734

 

$

3,822

 

Short-term debt

 

902

 

1,086

 

Other current liabilities

 

288

 

275

 

Total current liabilities

 

4,924

 

5,183

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discount of $14 and $15, respectively

 

6,011

 

6,010

 

Long-term debt under credit facilities and other

 

302

 

310

 

Other long-term liabilities and deferred credits

 

558

 

586

 

Total long-term liabilities

 

6,871

 

6,906

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (341,691,037 and 335,283,874 units outstanding, respectively)

 

6,828

 

6,388

 

General partner

 

270

 

249

 

Total partners’ capital excluding noncontrolling interests

 

7,098

 

6,637

 

Noncontrolling interests

 

531

 

509

 

Total partners’ capital

 

7,629

 

7,146

 

Total liabilities and partners’ capital

 

$

19,424

 

$

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

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(unaudited)

 

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

9,933

 

$

9,442

 

$

20,157

 

$

18,319

 

Transportation segment revenues

 

165

 

158

 

338

 

307

 

Facilities segment revenues

 

197

 

186

 

420

 

378

 

Total revenues

 

10,295

 

9,786

 

20,915

 

19,004

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

9,387

 

8,830

 

18,825

 

17,332

 

Field operating costs

 

343

 

319

 

684

 

568

 

General and administrative expenses

 

91

 

89

 

196

 

182

 

Depreciation and amortization

 

91

 

86

 

173

 

146

 

Total costs and expenses

 

9,912

 

9,324

 

19,878

 

18,228

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

383

 

462

 

1,037

 

776

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

11

 

9

 

23

 

16

 

Interest expense (net of capitalized interest of $10, $10, $19 and $18, respectively)

 

(75

)

(75

)

(152

)

(140

)

Other income/(expense), net

 

(1

)

 

(1

)

2

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

318

 

396

 

907

 

654

 

Current income tax expense

 

(8

)

(6

)

(53

)

(23

)

Deferred income tax expense

 

(10

)

(4

)

(17

)

(7

)

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

300

 

386

 

837

 

624

 

Net income attributable to noncontrolling interests

 

(8

)

(8

)

(16

)

(15

)

NET INCOME ATTRIBUTABLE TO PLAINS

 

$

292

 

$

378

 

$

821

 

$

609

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PLAINS:

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

197

 

$

303

 

$

631

 

$

465

 

GENERAL PARTNER

 

$

95

 

$

75

 

$

190

 

$

144

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.58

 

$

0.93

 

$

1.85

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.57

 

$

0.93

 

$

1.84

 

$

1.44

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING

 

340

 

323

 

338

 

319

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING

 

342

 

326

 

341

 

321

 

 

 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

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

300

 

$

386

 

$

837

 

$

624

 

Other comprehensive loss

 

(92

)

(108

)

(138

)

(49

)

Comprehensive income

 

208

 

278

 

699

 

575

 

Comprehensive income attributable to noncontrolling interests

 

(15

)

(6

)

(20

)

(9

)

Comprehensive income attributable to Plains

 

$

193

 

$

272

 

$

679

 

$

566

 

 

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

 

(16

)

 

(16

)

Deferred gain on cash flow hedges, net of tax

 

62

 

 

62

 

Currency translation adjustments

 

 

(184

)

(184

)

Total period activity

 

46

 

(184

)

(138

)

Balance at June 30, 2013

 

$

(74

)

$

16

 

$

(58

)

 

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)

 

 

 

Six Months Ended

 

 

 

June 30,

 

 

 

2013

 

2012

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

837

 

$

624

 

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

 

 

 

 

 

Depreciation and amortization

 

173

 

146

 

Inventory valuation adjustments

 

 

121

 

Equity-indexed compensation expense

 

78

 

60

 

Gain on sales of linefill and base gas

 

(3

)

(16

)

Net cash paid for terminated interest rate and foreign currency hedging instruments

 

 

(23

)

(Gain)/loss on foreign currency revaluation

 

(5

)

12

 

Deferred income tax expense

 

17

 

7

 

Other

 

(1

)

(3

)

Changes in assets and liabilities, net of acquisitions

 

241

 

(580

)

Net cash provided by operating activities

 

1,337

 

348

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(31

)

(1,534

)

Additions to property, equipment and other

 

(785

)

(544

)

Cash received for sales of linefill and base gas

 

14

 

49

 

Cash paid for purchases of linefill and base gas

 

(24

)

(29

)

Investment in unconsolidated entities

 

(112

)

 

Proceeds from sales of assets

 

3

 

19

 

Other investing activities

 

3

 

1

 

Net cash used in investing activities

 

(932

)

(2,038

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net borrowings/(repayments) on PAA’s revolving credit facility (Note 7)

 

(65

)

168

 

Net borrowings/(repayments) on PAA’s hedged inventory facility (Note 7)

 

(85

)

140

 

Net borrowings/(repayments) on PNG’s credit agreements (Note 7)

 

(36

)

37

 

Proceeds from the issuance of senior notes

 

 

1,247

 

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

 

331

 

535

 

Issuance of PNG common units

 

30

 

 

Short-term borrowings related to cash overdraft

 

 

48

 

Distributions paid to common unitholders (Note 9)

 

(384

)

(328

)

Distributions paid to general partner (Note 9)

 

(175

)

(135

)

Distributions paid to noncontrolling interests

 

(24

)

(24

)

Other financing activities

 

(2

)

(10

)

Net cash provided by/(used in) financing activities

 

(410

)

1,678

 

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(3

)

(2

)

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(8

)

(14

)

Cash and cash equivalents, beginning of period

 

24

 

26

 

Cash and cash equivalents, end of period

 

$

16

 

$

12

 

 

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

146

 

$

129

 

Income taxes, net of amounts refunded

 

$

18

 

$

48

 

 

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

 

 

631

 

190

 

821

 

16

 

837

 

Distributions

 

 

(384

)

(175

)

(559

)

(24

)

(583

)

Issuance of common units

 

5.9

 

324

 

7

 

331

 

 

331

 

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

 

 

16

 

2

 

18

 

2

 

20

 

Distribution equivalent right payments

 

 

(3

)

 

(3

)

 

(3

)

Other comprehensive income/(loss)

 

 

(139

)

(3

)

(142

)

4

 

(138

)

Issuance of PNG common units

 

 

6

 

 

6

 

24

 

30

 

Balance at June 30, 2013

 

341.7

 

$

6,828

 

$

270

 

$

7,098

 

$

531

 

$

7,629

 

 

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. 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.

 

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

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

 

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 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 six months ended June 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 six months ended June 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 six months ended June 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.

 

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.

 

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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 June 30, 2013 and December 31, 2012, we had received approximately $152 million and $173 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, at June 30, 2013 and December 31, 2012, we had received approximately $448 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, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables against each other) that cover a significant portion of our transactions and also serve to mitigate credit risk.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered.  We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts.  At June 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 June 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 June 30, 2013 and December 31, 2012, these assets were classified as held for sale on our condensed consolidated balance sheets (in “Other current assets”). A portion of the transaction closed on July 1, 2013, and closing of the balance is subject to the satisfaction of customary closing conditions.

 

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

 

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

 

 

 

June 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

 

5,484

 

barrels

 

$

471

 

$

85.89

 

9,492

 

barrels

 

$

737

 

$

77.64

 

NGL

 

8,366

 

barrels

 

316

 

$

37.77

 

9,472

 

barrels

 

388

 

$

40.96

 

Natural gas

 

23,058

 

Mcf

 

78

 

$

3.38

 

20,374

 

Mcf

 

60

 

$

2.94

 

Other

 

N/A

 

 

 

27

 

N/A

 

N/A

 

 

 

24

 

N/A

 

Inventory subtotal

 

 

 

 

 

892

 

 

 

 

 

 

 

1,209

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

10,026

 

barrels

 

585

 

$

58.35

 

9,919

 

barrels

 

583

 

$

58.78

 

NGL

 

1,358

 

barrels

 

64

 

$

47.13

 

1,400

 

barrels

 

70

 

$

50.00

 

Natural gas

 

16,965

 

Mcf

 

58

 

$

3.42

 

15,755

 

Mcf

 

54

 

$

3.43

 

Linefill and base gas subtotal

 

 

 

 

 

707

 

 

 

 

 

 

 

707

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

2,038

 

barrels

 

157

 

$

77.04

 

1,962

 

barrels

 

149

 

$

75.94

 

NGL

 

1,162

 

barrels

 

50

 

$

43.03

 

3,238

 

barrels

 

125

 

$

38.60

 

Long-term inventory subtotal

 

 

 

 

 

207

 

 

 

 

 

 

 

274

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

1,806

 

 

 

 

 

 

 

$

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.

 

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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. During the second quarter of 2012, we recorded a non-cash charge of approximately $121 million related to the writedown of our crude oil and NGL inventory due to declines in prices during the period. The recognition of this adjustment, which is a component of “Purchases and related costs” in our accompanying condensed consolidated statement of operations, was substantially offset by the recognition of unrealized gains on derivative instruments being utilized to hedge the future sales of our crude oil and NGL inventory. Substantially all of such unrealized gains were recorded to “Supply and Logistics segment revenues” on our condensed consolidated statement of operations. See Note 11 for discussion of our derivative and risk management activities. We did not recognize any writedowns of inventory during 2013.

 

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:

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustments

 

(16

)

(7

)

(4

)

(27

)

Purchase price accounting adjustments and other (1)

 

(5

)

 

 

(5

)

Balance at June 30, 2013

 

$

876

 

$

1,164

 

$

463

 

$

2,503

 

 


(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):

 

 

 

June 30,

 

December 31,

 

 

 

2013

 

2012

 

SHORT-TERM DEBT

 

 

 

 

 

Credit Facilities :

 

 

 

 

 

PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.3% and 1.6% at June 30, 2013 and December 31, 2012, respectively

 

$

575

 

$

665

 

PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 3.2% and 2.4% at June 30, 2013 and December 31, 2012, respectively (1)

 

25

 

92

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.0% and 2.1% at June 30, 2013 and December 31, 2012, respectively (2)

 

49

 

77

 

5.63% senior notes due December 2013 (3)

 

250

 

250

 

Other

 

3

 

2

 

Total short-term debt

 

902

 

1,086

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

Senior notes, net of unamortized discounts of $14 and $15 at June 30, 2013 and December 31, 2012, respectively

 

6,011

 

6,010

 

 

 

 

 

 

 

Credit Facilities and Other:

 

 

 

 

 

PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.0% and 2.1% at June 30, 2013 and December 31, 2012, respectively (2)

 

97

 

105

 

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

 

200

 

200

 

Other

 

5

 

5

 

Total long-term debt

 

6,313

 

6,320

 

Total debt (1) (2) (4)

 

$

7,215

 

$

7,406

 

 


(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.

 

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(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.

 

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

 

(4)                       Our fixed-rate senior notes (including current maturities) had a face value of approximately $6.3 billion at both June 30, 2013 and December 31, 2012.  We estimated the aggregate fair value of these notes as of June 30, 2013 and December 31, 2012 to be approximately $6.8 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 facilities and agreements approximates fair value as interest rates reflect current market rates.  The fair value estimates for both our senior notes and credit facilities and agreements are based upon observable market data and are classified within level 2 of the fair value hierarchy.

 

Borrowings and Repayments under Credit Agreements

 

Total borrowings under our credit agreements for the six months ended June 30, 2013 and 2012 were approximately $7.561 billion and $4.856 billion, respectively. Total repayments under our credit agreements were approximately $7.747 billion and $4.511 billion for the six months ended June 30, 2013 and 2012, respectively.

 

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.  At June 30, 2013 and December 31, 2012, we had outstanding letters of credit of approximately $50 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 six months ended June 30, 2013 and 2012 (in millions, except per unit data):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Basic Net Income per Limited Partner Unit

 

 

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

292

 

$

378

 

$

821

 

$

609

 

General partner’s incentive distribution (1)

 

(91

)

(69

)

(177

)

(134

)

General partner 2% ownership (1)

 

(4

)

(6

)

(13

)

(10

)

Net income available to limited partners

 

197

 

303

 

631

 

465

 

Undistributed earnings allocated and distributions to participating securities (1)

 

(1

)

(2

)

(5

)

(3

)

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

 

$

196

 

$

301

 

$

626

 

$

462

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

340

 

323

 

338

 

319

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.58

 

$

0.93

 

$

1.85

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income per Limited Partner Unit

 

 

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

292

 

$

378

 

$

821

 

$

609

 

General partner’s incentive distribution (1)

 

(91

)

(69

)

(177

)

(134

)

General partner 2% ownership (1)

 

(4

)

(6

)

(13

)

(10

)

Net income available to limited partners

 

197

 

303

 

631

 

465

 

Undistributed earnings allocated and distributions to participating securities (1)

 

(1

)

(1

)

(3

)

(2

)

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

 

$

196

 

$

302

 

$

628

 

$

463

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

340

 

323

 

338

 

319

 

Effect of dilutive securities: Weighted average LTIP units

 

2

 

3

 

3

 

2

 

Diluted weighted average number of limited partner units outstanding

 

342

 

326

 

341

 

321

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.57

 

$

0.93

 

$

1.84

 

$

1.44

 

 


(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
June 30,

 

Six Months Ended
June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Basic net income per limited partner unit impact

 

$

 

$

(0.19

)

$

(0.33

)

$

(0.18

)

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit impact

 

$

 

$

(0.20

)

$

(0.33

)

$

(0.18

)

 

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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 six 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

 

July 8, 2013

 

August 14, 2013 (1)

 

$

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 August 2, 2013, for the period April 1, 2013 through June 30, 2013.

 

PAA Continuous Offering Programs

 

On September 13, 2012, we entered into an equity distribution agreement with respect to the offer and sale, through our sales agents, of common units representing limited partner interests having an aggregate offering price of up to $500 million. The final sales under this equity distribution agreement occurred during May 2013. During the first six months of 2013, we issued an aggregate of approximately 5.1 million common units under this agreement, generating net proceeds of approximately $283 million, including our general partner’s proportionate capital contribution, net of approximately $3 million of commissions to our sales agents. The net proceeds from sales were used for general partnership purposes.

 

On May 28, 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. Sales of such common units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by our sales agent and us. Under the terms of the agreement, we have the option to sell common units to any of our sales agents as principal for its own account at a price to be agreed upon at the time of the sale. For any such sales, we will enter into a separate terms agreement with the sales agent.

 

Through June 30, 2013, we issued an aggregate of approximately 0.8 million common units under the May 2013 agreement, generating net proceeds of approximately $48 million, including our general partner’s proportionate capital contribution, net of less than $1 million of commissions to our sales agents. The net proceeds from sales were used for general partnership purposes.

 

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 six months of 2013, net of units tendered by employees for tax withholding obligations.

 

Noncontrolling Interests in Subsidiaries

 

As of June 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 six months of 2013, PNG issued an aggregate of approximately 1.4 million common units under this agreement, generating net proceeds of approximately $30 million, excluding our proportionate capital contribution for our general partner interest.

 

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As a result of PNG’s common unit issuances under its continuous offering program, we recorded an increase in noncontrolling interest of approximately $24 million and an increase to our partners’ capital of approximately $6 million. The increases result from the portion of the proceeds attributable to the respective ownership interests in PNG, adjusted for the impact of the dilution of our ownership interest resulting from the issuances.

 

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 Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Net income attributable to Plains

 

$

292

 

$

378

 

$

821

 

$

609

 

Transfers to the noncontrolling interests:

 

 

 

 

 

 

 

 

 

Increase in capital from sale of PNG units

 

6

 

 

6

 

 

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

 

$

298

 

$

378

 

$

827

 

$

609

 

 

Noncontrolling Interests Rollforward

 

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

 

 

 

Six Months Ended

 

 

 

June 30,

 

 

 

2013

 

2012

 

Beginning balance

 

$

509

 

$

524

 

Net income attributable to noncontrolling interests

 

16

 

15

 

Distributions to noncontrolling interests

 

(24

)

(24

)

Equity-indexed compensation expense

 

2

 

1

 

Other comprehensive income/(loss):

 

 

 

 

 

Reclassification adjustments

 

6

 

(7

)

Net deferred gain/(loss) on cash flow hedges

 

(2

)

1

 

Issuance of PNG common units

 

24

 

 

Ending balance

 

$

531

 

$

510

 

 

Note 10—Equity-Indexed Compensation Plans

 

We refer to the PAA and PNG LTIP Plans, Special PAA Awards, PNG Transaction Grants 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.:

 

 

 

Reserved for Future
Grants

 

Outstanding

 

Outstanding Units
Earned

 

 

Grant Date
Fair Value of Outstanding
Class B Units 
(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

 

26,000

 

 

N/A

 

Balance at June 30, 2013

 

13,375

 

186,625

 

156,250

 

 

$

51

 

 


(1)                       Of the grant date fair value, approximately $2 million was recognized as expense during the six months ended June 30, 2013.

 

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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. These awards were granted in conjunction with the cancellation of the Class B Units of PNGS GP LLC, which were terminated in February 2013.

 

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) (5)

 

 

 

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

 

$

47.57

 

 

0.4

 

$

17.34

 

Vested

 

(1.8

)

$

24.77

 

 

 

$

14.77

 

Cancelled or forfeited

 

(0.2

)

$

35.70

 

 

 

$

14.40

 

Outstanding at June 30, 2013

 

8.1

 

$

36.66

 

 

1.3

 

$

17.57

 

 


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

(2)                       Amounts include Special PAA Awards.

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

(4)                       Amounts include PNG Transaction Grants.

(5)                       Less than 0.1 million PNG common units vested and less than 0.1 million common units were forfeited during the six months ended June 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

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Equity-indexed compensation expense

 

$

27

 

$

20

 

$

78

 

$

60

 

LTIP unit-settled vestings (1)

 

$

46

 

$

33

 

$

46

 

$

58

 

LTIP cash-settled vestings

 

$

60

 

$

29

 

$

60

 

$

65

 

DER cash payments

 

$

2

 

$

2

 

$

4

 

$

4

 

 


(1)                       For each of the three and six months ended June 30, 2012, approximately $1 million relates to unit-settled vestings that were settled with PNG common units.

 

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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 June 30, 2013, net derivative positions related to these activities included:

 

·                  An average of 332,800 barrels per day net long position (total of 10.3 million barrels) associated with our crude oil purchases, which was unwound ratably during July 2013 to match monthly average pricing.

 

·                  A net short spread position averaging approximately 27,800 barrels per day (total of 11.0 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through September 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 13,000 barrels per day (total of 2.0 million barrels) of WTS/WTI crude oil basis futures through December 2013, which hedge anticipated purchases and 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 3,400 barrels per day (total of 0.5 million barrels) of LLS/WTI crude oil basis futures through December 2013, which hedge anticipated purchases and 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 2,300 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 1.9 Bcf through April 2016 related to anticipated base gas requirements.

 

·                  A short position of approximately 22.9 Bcf through December 2013 related to anticipated sales of owned natural gas 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 June 30, 2013, we used derivatives to manage the risk of not utilizing approximately 2.4 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

 

Inventory Storage — 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 June 30, 2013, we had derivatives totaling approximately 6.6 million barrels hedging our inventory.

 

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 June 30, 2013, our PLA hedges included (i) a net short position for an average of approximately 1,700 barrels per day (total of 1.6 million barrels) through December 2015, (ii) a long put option position of approximately 0.1 million barrels through December 2013 and (iii) a long call option position of approximately 0.4 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 purchase of natural gas and the subsequent sale of the individual specification products.  As of June 30, 2013, we had a long natural gas position of approximately 13.7 Bcf through March 2015, a short propane position of approximately 2.4 million barrels through March 2015, a short butane position of approximately 0.7 million barrels through March 2015 and a short WTI position of approximately 0.2 million barrels through March 2015. In addition, we had a long power position of 0.6 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 June 30, 2013, AOCI includes deferred losses of approximately $90 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 June 30, 2013 (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

 

5 forward starting swaps (30-year)

 

$

125

 

6/16/2014

 

3.39

%

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 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 June 30, 2013, AOCI includes net deferred gains of approximately $3 million that relate to foreign currency derivatives that were designated for hedge accounting.

 

As of June 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 June 30, 2013 (in millions):

 

 

 

 

 

USD

 

CAD

 

Average Exchange Rate
USD to CAD

 

Forward exchange contracts that exchange CAD for USD:

 

 

 

 

 

 

 

 

 

 

 

2013

 

$

214

 

$

224

 

$1.00 - $1.05

 

 

 

2014

 

 

42

 

 

44

 

$1.00 - $1.06

 

 

 

2015

 

 

9

 

 

9

 

$1.00 - $1.07

 

 

 

 

 

$

265

 

$

277

 

$1.00 - $1.05

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward exchange contracts that exchange USD for CAD:

 

 

 

 

 

 

 

 

 

 

 

2013

 

$

209

 

$

216

 

$1.00 - $1.03

 

 

 

2014

 

42

 

43

 

$1.00 - $1.03

 

 

 

2015

 

 

9

 

 

9

 

$1.00 - $1.06

 

 

 

 

 

$

260

 

$

268

 

$1.00 - $1.03

 

 

 

 

 

 

 

 

 

 

 

Net position by currency:

 

 

 

 

 

 

 

 

 

 

 

2013

 

$

5

 

$

8

 

 

 

 

 

2014

 

 

 

 

1

 

 

 

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

$

5

 

$

9

 

 

 

 

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.  For our interest rate swaps that qualify as fair value hedges, changes in the fair value of the derivatives are recognized in earnings each period.  Additionally, the change in fair value of the hedged item, attributable to the hedged risk, is recognized as a basis adjustment to the hedged item and is also 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 six months ended June 30, 2013 and 2012 is as follows (in millions):

 

 

 

Three Months Ended June 30, 2013

 

Three Months Ended June 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 
(2)

 

Total

 

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

 

Other
gain/(loss)
recognized
in income

 

Derivatives
Not
Designated
as a
Hedge 
(2)

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

21

 

$

 

$

21

 

$

42

 

 

$

(97

)

$

1

 

$

199

 

$

103

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

(9

)

 

 

(9

)

 

1

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

 

 

 

 

 

37

 

 

(1

)

36

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Field operating costs

 

 

 

4

 

4

 

 

 

 

(4

)

(4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(2

)

 

 

(2

)

 

(1

)

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

 

 

 

 

 

 

 

(1

)

(1

)