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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended September 30, 2014

 

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 Web site, 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.

 

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, 2014, there were 372,033,831 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: As of September 30, 2014 and December 31, 2013

3

Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2014 and 2013

4

Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2014  and 2013

5

Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income / (Loss): For the nine months ended September 30, 2014 and 2013

5

Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2014 and 2013

6

Condensed Consolidated Statements of Changes in Partners’ Capital: For the nine months ended September 30, 2014 and 2013

7

Notes to the Condensed Consolidated Financial Statements:

 

1. Organization and Basis of Consolidation and Presentation

8

2. Recent Accounting Pronouncements

9

3. Accounts Receivable

9

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

10

5. Goodwill

11

6. Debt

11

7. Net Income Per Limited Partner Unit

12

8. Partners’ Capital and Distributions

14

9. Equity-Indexed Compensation Plans

14

10. Derivatives and Risk Management Activities

16

11. Commitments and Contingencies

23

12. Operating Segments

24

13. Related Party Transactions

26

14. Subsequent Events

27

 

 

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

28

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

46

Item 4. CONTROLS AND PROCEDURES

47

 

 

PART II. OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

49

Item 1A. RISK FACTORS

49

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

49

Item 3. DEFAULTS UPON SENIOR SECURITIES

49

Item 4. MINE SAFETY DISCLOSURES

49

Item 5. OTHER INFORMATION

49

Item 6. EXHIBITS

49

SIGNATURES

50

 

2



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

Item 1.                                  UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

 

 

 

September 30,

 

December 31,

 

 

 

2014

 

2013

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

34

 

$

41

 

Trade accounts receivable and other receivables, net

 

3,522

 

3,638

 

Inventory

 

1,314

 

1,065

 

Other current assets

 

290

 

220

 

Total current assets

 

5,160

 

4,964

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

13,816

 

12,473

 

Accumulated depreciation

 

(1,851

)

(1,654

)

Property and equipment, net

 

11,965

 

10,819

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

2,481

 

2,503

 

Linefill and base gas

 

903

 

798

 

Long-term inventory

 

270

 

251

 

Investments in unconsolidated entities

 

582

 

485

 

Other, net

 

476

 

540

 

Total assets

 

$

21,837

 

$

20,360

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

4,169

 

$

3,983

 

Short-term debt

 

976

 

1,113

 

Other current liabilities

 

423

 

315

 

Total current liabilities

 

5,568

 

5,411

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discount of $16 and $15, respectively

 

7,609

 

6,710

 

Long-term debt under credit facilities and other

 

4

 

5

 

Other long-term liabilities and deferred credits

 

526

 

531

 

Total long-term liabilities

 

8,139

 

7,246

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 11)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (371,468,177 and 359,133,200 units outstanding, respectively)

 

7,740

 

7,349

 

General partner

 

331

 

295

 

Total partners’ capital excluding noncontrolling interests

 

8,071

 

7,644

 

Noncontrolling interests

 

59

 

59

 

Total partners’ capital

 

8,130

 

7,703

 

Total liabilities and partners’ capital

 

$

21,837

 

$

20,360

 

 

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,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(unaudited)

 

(unaudited)

 

REVENUES

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

10,788

 

$

10,386

 

$

32,988

 

$

30,542

 

Transportation segment revenues

 

198

 

179

 

574

 

517

 

Facilities segment revenues

 

141

 

138

 

443

 

558

 

Total revenues

 

11,127

 

10,703

 

34,005

 

31,617

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

10,166

 

9,909

 

31,116

 

28,733

 

Field operating costs

 

382

 

326

 

1,078

 

1,010

 

General and administrative expenses

 

78

 

79

 

257

 

276

 

Depreciation and amortization

 

97

 

93

 

293

 

265

 

Total costs and expenses

 

10,723

 

10,407

 

32,744

 

30,284

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

404

 

296

 

1,261

 

1,333

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

29

 

19

 

73

 

42

 

Interest expense (net of capitalized interest of $12, $11, $33 and $30, respectively)

 

(85

)

(72

)

(246

)

(224

)

Other income/(expense), net

 

(4

)

3

 

(2

)

2

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

344

 

246

 

1,086

 

1,153

 

Current income tax expense

 

(10

)

(17

)

(62

)

(69

)

Deferred income tax benefit/(expense)

 

(10

)

8

 

(28

)

(10

)

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

324

 

237

 

996

 

1,074

 

Net income attributable to noncontrolling interests

 

(1

)

(6

)

(2

)

(22

)

NET INCOME ATTRIBUTABLE TO PAA

 

$

323

 

$

231

 

$

994

 

$

1,052

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PAA:

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS

 

$

195

 

$

133

 

$

630

 

$

764

 

GENERAL PARTNER

 

$

128

 

$

98

 

$

364

 

$

288

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.52

 

$

0.38

 

$

1.71

 

$

2.23

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.52

 

$

0.38

 

$

1.70

 

$

2.22

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING

 

370

 

343

 

365

 

340

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING

 

371

 

345

 

367

 

342

 

 

 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

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(unaudited)

 

(unaudited)

 

Net income

 

$

324

 

$

237

 

$

996

 

$

1,074

 

Other comprehensive income/(loss)

 

(167

)

39

 

(211

)

(99

)

Comprehensive income

 

157

 

276

 

785

 

975

 

Comprehensive income attributable to noncontrolling interests

 

(1

)

(7

)

(2

)

(27

)

Comprehensive income attributable to PAA

 

$

156

 

$

269

 

$

783

 

$

948

 

 

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

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

(in millions)

 

 

 

Derivative

 

Translation

 

 

 

 

 

Instruments

 

Adjustments

 

Total

 

 

 

(unaudited)

 

Balance at December 31, 2013

 

$

(77

)

$

(20

)

$

(97

)

 

 

 

 

 

 

 

 

Reclassification adjustments

 

16

 

 

16

 

Deferred loss on cash flow hedges, net of tax

 

(57

)

 

(57

)

Currency translation adjustments

 

 

(170

)

(170

)

Total period activity

 

(41

)

(170

)

(211

)

Balance at September 30, 2014

 

$

(118

)

$

(190

)

$

(308

)

 

 

 

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,

 

 

 

2014

 

2013

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

996

 

$

1,074

 

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

 

 

 

 

 

Depreciation and amortization

 

293

 

265

 

Equity-indexed compensation expense

 

90

 

96

 

Inventory valuation adjustments

 

37

 

7

 

Deferred income tax expense

 

28

 

10

 

Gain on sales of linefill and base gas

 

(8

)

(5

)

(Gain)/loss on foreign currency revaluation

 

10

 

(6

)

Settlement of terminated interest rate hedging instruments

 

(7

)

8

 

Equity earnings in unconsolidated entities, net of distributions

 

1

 

(7

)

Other

 

10

 

 

Changes in assets and liabilities, net of acquisitions

 

(172

)

152

 

Net cash provided by operating activities

 

1,278

 

1,594

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(10

)

(28

)

Additions to property, equipment and other

 

(1,424

)

(1,217

)

Cash received for sales of linefill and base gas

 

24

 

25

 

Cash paid for purchases of linefill and base gas

 

(159

)

(61

)

Investment in unconsolidated entities

 

(98

)

(124

)

Proceeds from sales of assets

 

2

 

62

 

Other investing activities

 

1

 

3

 

Net cash used in investing activities

 

(1,664

)

(1,340

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net repayments under PAA senior secured hedged inventory facility (Note 6)

 

 

(659

)

Net repayments under PAA senior unsecured revolving credit facility (Note 6)

 

 

(92

)

Net repayments under PNG credit agreement

 

 

(32

)

Net borrowings/(repayments) under PAA commercial paper program (Note 6)

 

(683

)

319

 

Proceeds from the issuance of senior notes (Note 6)

 

1,447

 

699

 

Net proceeds from the issuance of common units (Note 8)

 

655

 

392

 

Contributions from general partner

 

14

 

8

 

Net proceeds from the issuance of PNG common units

 

 

40

 

Distributions paid to common unitholders (Note 8)

 

(688

)

(585

)

Distributions paid to general partner (Note 8)

 

(344

)

(270

)

Distributions paid to noncontrolling interests

 

(2

)

(37

)

Other financing activities

 

(19

)

(25

)

Net cash provided by/(used in) financing activities

 

380

 

(242

)

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(1

)

(3

)

 

 

 

 

 

 

Net increase/(decrease) in cash and cash equivalents

 

(7

)

9

 

Cash and cash equivalents, beginning of period

 

41

 

24

 

Cash and cash equivalents, end of period

 

$

34

 

$

33

 

 

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

237

 

$

230

 

Income taxes, net of amounts refunded

 

$

135

 

$

19

 

 

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 STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

 

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

Total

 

 

 

Common Units

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Units

 

Amount

 

Partner

 

Interests

 

Interests

 

Capital

 

 

 

(unaudited)

 

Balance at December 31, 2013

 

359.1

 

$

7,349

 

$

295

 

$

7,644

 

$

59

 

$

7,703

 

Net income

 

 

630

 

364

 

994

 

2

 

996

 

Distributions

 

 

(688

)

(344

)

(1,032

)

(2

)

(1,034

)

Issuance of common units

 

11.8

 

655

 

14

 

669

 

 

669

 

Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations

 

0.6

 

(18

)

1

 

(17

)

 

(17

)

Equity-indexed compensation expense

 

 

25

 

5

 

30

 

 

30

 

Distribution equivalent right payments

 

 

(5

)

 

(5

)

 

(5

)

Other comprehensive loss

 

 

(207

)

(4

)

(211

)

 

(211

)

Other

 

 

(1

)

 

(1

)

 

(1

)

Balance at September 30, 2014

 

371.5

 

$

7,740

 

$

331

 

$

8,071

 

$

59

 

$

8,130

 

 

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

Total

 

 

 

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, net of units tendered by employees to satisfy tax withholding obligations

 

0.5

 

(11

)

 

(11

)

 

(11

)

Equity-indexed compensation expense

 

 

24

 

4

 

28

 

3

 

31

 

Distribution equivalent right payments

 

 

(4

)

 

(4

)

 

(4

)

Other comprehensive income/(loss)

 

 

(102

)

(2

)

(104

)

5

 

(99

)

Issuance of PNG common units

 

 

8

 

 

8

 

32

 

40

 

Other

 

 

(1

)

 

(1

)

 

(1

)

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 THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

Note 1—Organization and Basis of Consolidation and Presentation

 

Organization

 

Plains All American Pipeline, L.P. is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. 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.

 

We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. The term NGL includes ethane and natural gasoline products as well as products commonly referred to as liquefied petroleum gas (“LPG”), such as propane and butane. When used in this Form 10-Q, NGL refers to all NGL products including LPG. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 12 for further discussion of our operating segments.

 

Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP LLC, AAP also owns all of our incentive distribution rights (“IDRs”). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (NYSE: PAGP) is the sole member of GP LLC, and at September 30, 2014, owned a 22.4% limited partner interest in AAP. GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to our “general partner,” as the context requires, include any or all of PAA GP LLC, AAP and GP LLC.

 

Definitions

 

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

 

AOCI

=

 

Accumulated other comprehensive income

Bcf

=

 

Billion cubic feet

Btu

=

 

British thermal unit

CAD

=

 

Canadian dollar

DERs

=

 

Distribution equivalent rights

EBITDA

=

 

Earnings before interest, taxes, depreciation and amortization

FASB

=

 

Financial Accounting Standards Board

GAAP

=

 

Generally accepted accounting principles in the United States

ICE

=

 

IntercontinentalExchange

LIBOR

=

 

London Interbank Offered Rate

LTIP

=

 

Long-term incentive plan

Mcf

=

 

Thousand cubic feet

MLP

=

 

Master limited partnership

NYMEX

=

 

New York Mercantile Exchange

PLA

=

 

Pipeline loss allowance

PNG

=

 

PAA Natural Gas Storage, L.P.

SEC

=

 

Securities and Exchange Commission

USD

=

 

United States dollar

White Cliffs

=

 

White Cliffs Pipeline, LLC

WTI

=

 

West Texas Intermediate

 

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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 2013 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, 2013 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, 2014 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 2013 Annual Report on Form 10-K, no new accounting pronouncements have become effective or have been issued during the nine months ended September 30, 2014 that are of significance or potential significance to us.

 

In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance becomes effective for interim and annual periods beginning after December 15, 2016 and can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We are currently evaluating which transition approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

In April 2014, the FASB issued guidance that modifies the criteria under which assets to be disposed of are evaluated to determine if such assets qualify as a discontinued operation and requires new disclosures for both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2014. Early adoption is permitted but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issue. We are currently evaluating the provisions of this authoritative guidance and assessing its impact, but do not believe our adoption will have a material impact on our financial position, results of operations or cash flows.

 

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 became effective for interim and annual periods beginning after December 15, 2013. We adopted this guidance on January 1, 2014. Our adoption did not have a material 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 NGL and natural gas storage. 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 advance cash payments, standby letters of credit or parental guarantees.  As of September 30, 2014 and December 31, 2013, we had received $181 million and $117 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of September 30, 2014 and December 31, 2013, we had received $278 million and $426 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.

 

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Table of Contents

 

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, 2014 and December 31, 2013, 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 $4 million and $5 million at September 30, 2014 and December 31, 2013, respectively.  Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

Note 4—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, 2014

 

 

December 31, 2013

 

 

 

 

 

Unit of

 

Carrying

 

Price/

 

 

 

 

Unit of

 

Carrying

 

Price/

 

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

 

Volumes

 

Measure

 

Value

 

Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

5,665

 

barrels

 

$

476

 

$

84.02

 

 

6,951

 

barrels

 

$

540

 

$

77.69

 

NGL

 

17,392

 

barrels

 

699

 

$

40.19

 

 

8,061

 

barrels

 

352

 

$

43.67

 

Natural gas

 

29,245

 

Mcf

 

119

 

$

4.07

 

 

40,505

 

Mcf

 

150

 

$

3.70

 

Other

 

N/A

 

 

 

20

 

N/A

 

 

N/A

 

 

 

23

 

N/A

 

Inventory subtotal

 

 

 

 

 

1,314

 

 

 

 

 

 

 

 

1,065

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

11,390

 

barrels

 

715

 

$

62.77

 

 

10,966

 

barrels

 

679

 

$

61.92

 

NGL

 

1,214

 

barrels

 

54

 

$

44.48

 

 

1,341

 

barrels

 

62

 

$

46.23

 

Natural gas

 

28,612

 

Mcf

 

134

 

$

4.68

 

 

16,615

 

Mcf

 

57

 

$

3.43

 

Linefill and base gas subtotal

 

 

 

 

 

903

 

 

 

 

 

 

 

 

798

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

2,557

 

barrels

 

207

 

$

80.95

 

 

2,498

 

barrels

 

202

 

$

80.86

 

NGL

 

1,681

 

barrels

 

63

 

$

37.48

 

 

1,161

 

barrels

 

49

 

$

42.20

 

Long-term inventory subtotal

 

 

 

 

 

270

 

 

 

 

 

 

 

 

251

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

2,487

 

 

 

 

 

 

 

 

$

2,114

 

 

 

 


(1)                                     Price per unit of measure is comprised of 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 did not record any such charges during the three months ended September 30, 2014. We recorded a charge of $37 million during the nine months ended September 30, 2014 related to the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014. During the three and nine months ended September 30, 2013, we recorded a charge of $7 million, primarily related to the writedown of our crude oil inventory due to declines in prices during the period. These adjustments are a component of “Purchases and related costs” on our accompanying condensed consolidated statements of operations. The recognition of the adjustment in 2013 was substantially offset by the recognition of gains on derivative instruments being utilized to hedge the future sales of our crude oil inventory.  Substantially all of such gains were recorded to “Supply and Logistics segment revenues” on our accompanying condensed consolidated statements of operations.  See Note 10 for discussion of our derivatives and risk management activities.

 

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Table of Contents

 

Note 5—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, 2013

 

$

878

 

$

1,162

 

$

463

 

$

2,503

 

Foreign currency translation adjustments

 

(14

)

(6

)

(3

)

(23

)

Other

 

 

1

 

 

1

 

Balance at September 30, 2014

 

$

864

 

$

1,157

 

$

460

 

$

2,481

 

 

We completed our annual goodwill impairment test as of June 30, 2014 and determined that there was no impairment of goodwill.

 

Note 6—Debt

 

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

 

 

 

September 30,

 

December 31,

 

 

 

2014

 

2013

 

SHORT-TERM DEBT

 

 

 

 

 

PAA commercial paper notes, bearing a weighted-average interest rate of 0.30% and 0.33%, respectively (1)

 

$

423

 

$

1,109

 

PAA senior notes:

 

 

 

 

 

5.25% senior notes due June 2015

 

150

 

 

3.95% senior notes due September 2015

 

400

 

 

Other

 

3

 

4

 

Total short-term debt

 

976

 

1,113

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

PAA senior notes:

 

 

 

 

 

5.25% senior notes due June 2015

 

 

150

 

3.95% senior notes due September 2015

 

 

400

 

5.88% senior notes due August 2016

 

175

 

175

 

6.13% senior notes due January 2017

 

400

 

400

 

6.50% senior notes due May 2018

 

600

 

600

 

8.75% senior notes due May 2019

 

350

 

350

 

5.75% senior notes due January 2020

 

500

 

500

 

5.00% senior notes due February 2021

 

600

 

600

 

3.65% senior notes due June 2022

 

750

 

750

 

2.85% senior notes due January 2023

 

400

 

400

 

3.85% senior notes due October 2023

 

700

 

700

 

3.60% senior notes due November 2024

 

750

 

 

6.70% senior notes due May 2036

 

250

 

250

 

6.65% senior notes due January 2037

 

600

 

600

 

5.15% senior notes due June 2042

 

500

 

500

 

4.30% senior notes due January 2043

 

350

 

350

 

4.70% senior notes due June 2044

 

700

 

 

Unamortized discounts

 

(16

)

(15

)

PAA senior notes, net of unamortized discounts

 

7,609

 

6,710

 

Other

 

4

 

5

 

Total long-term debt

 

7,613

 

6,715

 

Total debt (2) 

 

$

8,589

 

$

7,828

 

 


(1)                                     PAA commercial paper notes are backstopped by the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility, which mature in August 2019 and August 2017, respectively; as such, any borrowings under the PAA commercial paper program effectively reduce the available capacity under these facilities. At September 30, 2014 and December 31, 2013, we classified $423 million and approximately $1.1 billion, respectively, of borrowings under our commercial paper program as short-term. 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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Table of Contents

 

(2)                                     Our fixed-rate senior notes (including current maturities) had a face value of approximately $8.2 billion and $6.7 billion at September 30, 2014 and December 31, 2013, respectively. We estimated the aggregate fair value of these notes as of September 30, 2014 and December 31, 2013 to be approximately $8.8 billion and $7.2 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 commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified within Level 2 of the fair value hierarchy.  See Note 10 for additional discussion of the fair value hierarchy.

 

Credit Facilities

 

In August 2014, we extended the maturity dates of our senior secured hedged inventory facility and our senior unsecured revolving credit facility by one year through the exercise of the option included in the current credit agreements. Our senior secured hedged inventory facility and our senior unsecured revolving credit facility now mature in August 2017 and August 2019, respectively.

 

Borrowings and Repayments

 

Total borrowings under our credit agreements and the commercial paper program for the nine months ended September 30, 2014 and 2013 were approximately $55.6 billion and $12.7 billion, respectively. Total repayments under our credit agreements and the commercial paper program for the nine months ended September 30, 2014 and 2013 were approximately $56.3 billion and $13.2 billion, 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, 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, 2014 and December 31, 2013, we had outstanding letters of credit of $66 million and $41 million, respectively.

 

Senior Notes Issuances

 

On April 23, 2014, we completed the issuance of $700 million, 4.70% senior notes due 2044 at a public offering price of 99.734%. Interest payments are due on June 15 and December 15 of each year, commencing on December 15, 2014. In anticipation of the issuance of these senior notes, we entered into $250 million notional principal amount of U.S. treasury locks in March and April 2014 to hedge the treasury rate portion of the interest rate on a portion of the notes. We terminated these treasury locks in April 2014. See Note 10 for additional disclosure.

 

On September 9, 2014, we completed the issuance of $750 million, 3.60% senior notes due 2024 at a public offering price of 99.842%. Interest payments are due on May 1 and November 1 of each year, commencing on May 1, 2015.

 

Commercial Paper Program

 

Effective October 20, 2014, the maximum aggregate borrowing capacity under our commercial paper program was increased from $1.5 billion to $3.0 billion.

 

Note 7—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 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.

 

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Table of Contents

 

The Partnership calculates basic and diluted net income per limited partner unit by dividing net income attributable to PAA (after deducting the amount allocated to the general partner’s interest, 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 FASB.  See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

 

The following table sets forth the computation of basic and diluted net income per limited partner unit for the three and nine months ended September 30, 2014 and 2013 (in millions, except per unit data):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Basic Net Income per Limited Partner Unit

 

 

 

 

 

 

 

 

 

Net income attributable to PAA

 

$

323

 

$

231

 

$

994

 

$

1,052

 

Less: General partner’s incentive distribution (1)

 

(124

)

(95

)

(351

)

(272

)

Less: General partner 2% ownership (1)

 

(4

)

(3

)

(13

)

(16

)

Net income available to limited partners

 

195

 

133

 

630

 

764

 

Less: Undistributed earnings allocated and distributions to participating securities (1)

 

(1

)

(1

)

(5

)

(5

)

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

 

$

194

 

$

132

 

$

625

 

$

759

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average limited partner units outstanding

 

370

 

343

 

365

 

340

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.52

 

$

0.38

 

$

1.71

 

$

2.23

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income per Limited Partner Unit

 

 

 

 

 

 

 

 

 

Net income attributable to PAA

 

$

323

 

$

231

 

$

994

 

$

1,052

 

Less: General partner’s incentive distribution (1)

 

(124

)

(95

)

(351

)

(272

)

Less: General partner 2% ownership (1)

 

(4

)

(3

)

(13

)

(16

)

Net income available to limited partners

 

195

 

133

 

630

 

764

 

Less: Undistributed earnings allocated and distributions to participating securities (1)

 

(1

)

(1

)

(5

)

(4

)

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

 

$

194

 

$

132

 

$

625

 

$

760

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average limited partner units outstanding

 

370

 

343

 

365

 

340

 

Effect of dilutive securities: Weighted average LTIP units

 

1

 

2

 

2

 

2

 

Diluted weighted average limited partner units outstanding

 

371

 

345

 

367

 

342

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.52

 

$

0.38

 

$

1.70

 

$

2.22

 

 


(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.

 

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Table of Contents

 

Pursuant to the terms of our partnership agreement, the general partner’s incentive distribution is limited to a percentage 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 net income 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,

 

 

 

2014

 

2013

 

2014

 

2013

 

Basic net income per limited partner unit impact

 

$

 

$

 

$

 

$

(0.23

)

 

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit impact

 

$

 

$

 

$

 

$

(0.23

)

 

Note 8—Partners’ Capital and Distributions

 

Distributions

 

The following table details the distributions paid during or pertaining to the first nine months of 2014, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):

 

 

 

 

 

Distributions Paid

 

Distributions

 

 

 

 

 

Common

 

General Partner

 

 

 

per limited

 

Date Declared

 

Distribution Date

 

Units

 

Incentive

 

2%

 

Total

 

partner unit

 

October 8, 2014

 

November 14, 2014 (1)

 

$

245

 

$

124

 

$

5

 

$

374

 

 

$

0.6600

 

July 8, 2014

 

August 14, 2014

 

$

238

 

$

117

 

$

5

 

$

360

 

 

$

0.6450

 

April 7, 2014

 

May 15, 2014

 

$

229

 

$

110

 

$

5

 

$

344

 

 

$

0.6300

 

January 9, 2014

 

February 14, 2014

 

$

221

 

$

102

 

$

5

 

$

328

 

 

$

0.6150

 

 


(1)                                  Payable to unitholders of record at the close of business on October 31, 2014 for the period July 1, 2014 through September 30, 2014.

 

Continuous Offering Program

 

In August 2014, we entered into an equity distribution agreement with several financial institutions pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests having an aggregate offering price of up to $900 million. During the nine months ended September 30, 2014, we issued an aggregate of approximately 11.8 million common units under our continuous offering program, generating proceeds of $669 million, including our general partner’s proportionate capital contribution of $14 million, net of $7 million of commissions to our sales agents.

 

Noncontrolling Interests in Subsidiaries

 

As of September 30, 2014, noncontrolling interests in subsidiaries consisted of a 25% interest in SLC Pipeline LLC. On December 31, 2013, we purchased the noncontrolling interests in PNG, and PNG became our wholly-owned subsidiary.

 

Note 9—Equity-Indexed Compensation Plans

 

We refer to the PAA LTIPs and AAP Management Units 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 2013 Annual Report on Form 10-K.

 

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Table of Contents

 

PAA LTIP Awards

 

Activity for LTIP awards denominated in PAA units under our equity-indexed compensation plans is summarized in the following table (units in millions):

 

 

 

Units (1)

 

Weighted Average Grant
Date
Fair Value per Unit

 

Outstanding at December 31, 2013

 

8.4

 

$

36.97

 

Granted

 

1.1

 

$

47.27

 

Vested (2)

 

(1.9

)

$

25.54

 

Cancelled or forfeited

 

(0.3

)

$

39.63

 

Outstanding at September 30, 2014

 

7.3

 

$

41.28

 

 


(1)                                     Amounts do not include AAP Management Units.

 

(2)                                     During the nine months ended September 30, 2014, approximately 0.6 million PAA common units were issued, net of approximately 0.3 million units withheld for taxes, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.0 million units) that vested during the nine months ended September 30, 2014 were settled in cash.

 

AAP Management Units

 

Activity for AAP Management Units is summarized in the following table (in millions):

 

 

 

Reserved for Future
Grants

 

Outstanding

 

Outstanding Units
Earned

 

 

Grant Date
Fair Value Of Outstanding AAP
Management Units 
(1)

 

Balance at December 31, 2013

 

3.5

 

48.6

 

47.0

 

 

$

51

 

Granted

 

(0.4

)

0.4

 

 

 

11

 

Earned

 

N/A

 

N/A

 

0.8

 

 

N/A

 

Balance at September 30, 2014

 

3.1

 

49.0

 

47.8

 

 

$

62

 

 


(1)                                     Of the $62 million grant date fair value, approximately $54 million had been recognized through September 30, 2014. Approximately $5 million of such amount was recognized as expense during the nine months ended September 30, 2014.

 

Other Consolidated Equity-Indexed Compensation Plan Information

 

The table below summarizes the expense recognized and the value of vested LTIPs (settled both in common units and cash) under 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,

 

 

 

2014

 

2013

 

2014

 

2013

 

Equity-indexed compensation expense

 

$

22

 

$

17

 

$

90

 

$

96

 

LTIP unit-settled vestings

 

$

1

 

$

1

 

$

52

 

$

47

 

LTIP cash-settled vestings

 

$

 

$

 

$

52

 

$

61

 

DER cash payments

 

$

2

 

$

2

 

$

6

 

$

5

 

 

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Table of Contents

 

Note 10—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 involve certain commodity price-related risks that we manage in various ways, including through 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, 2014, net derivative positions related to these activities included:

 

·                  An average of 248,700 barrels per day net long position (total of 7.7 million barrels) associated with our crude oil purchases, which was unwound ratably during October 2014 to match monthly average pricing.

 

·                  A net short time spread position averaging approximately 19,900 barrels per day (total of 11.5 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2016.  Our use of these derivatives does not expose us to outright price risk.

 

·                  An average of 15,200 barrels per day (total of 6.5 million barrels) of crude oil grade spread positions through December 2015. These derivatives allow us to lock in grade basis differentials. Our use of these derivatives does not expose us to outright price risk.

 

·                  A net short position of approximately 25.1 Bcf through April 2016 related to anticipated sales of natural gas inventory and base gas requirements.

 

·                  A net short position of approximately 12.1 million barrels through December 2015 related to the anticipated sales of our crude oil, NGL and refined products 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 September 30, 2014, our PLA hedges included a net short position for an average of approximately 1,400 barrels per day (total of 1.1 million barrels) through December 2016 and a long call position of approximately 0.6 million barrels through December 2016.

 

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, 2014, we had a long natural gas position of approximately 33.3 Bcf through December 2016, a short propane position of approximately 5.4 million barrels through December 2016 and a short butane position of approximately 1.6 million barrels through December 2016.

 

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Table of Contents

 

To the extent they qualify and we decide to make the election, all of our commodity derivatives where we elect hedge accounting are designated as cash flow hedges.  We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase normal sale scope exception.  Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchase normal sale 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, 2014, AOCI includes deferred losses of $108 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, 2014 (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

 

10 forward starting swaps (30-year)

 

$

250

 

6/15/2015

 

3.60%

 

Cash flow hedge

 

 

In anticipation of our April 2014 issuance of senior notes, we entered into an aggregate of five treasury lock agreements in March and April 2014 for a combined notional amount of $250 million at a locked in rate of 3.62%.  The treasury locks were designated as cash flow hedges, thus, changes in fair value are deferred in AOCI.  In connection with our April 2014 senior notes issuance, these treasury locks were terminated prior to maturity for an aggregate cash payment of $7 million.  The effective portion of the treasury locks was deferred in AOCI and will be amortized to interest expense over the life of the senior notes.

 

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 risk of unfavorable changes in exchange rates.  These instruments include foreign currency exchange contracts and forwards.

 

As of September 30, 2014, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) 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, 2014 (in millions):

 

 

 

 

 

USD

 

CAD

 

Average Exchange Rate USD
to CAD

 

Forward exchange contracts that exchange CAD for USD:

 

 

 

 

 

 

 

 

 

 

 

2014

 

$

284

 

$

319

 

$1.00 - $1.12

 

 

 

2015

 

178

 

200

 

$1.00 - $1.12

 

 

 

 

 

$

462

 

$

519

 

$1.00 - $1.12

 

 

 

 

 

 

 

 

 

 

 

Forward exchange contracts that exchange USD for CAD:

 

 

 

 

 

 

 

 

 

 

 

2014

 

$

284

 

$

313

 

$1.00 - $1.10

 

 

 

2015

 

178

 

195

 

$1.00 - $1.09

 

 

 

 

 

$

462

 

$

508

 

$1.00 - $1.10

 

 

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Table of Contents

 

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.

 

A summary of the impact of our derivative activities recognized in earnings for the three and nine months ended September 30, 2014 and 2013 is as follows (in millions):

 

 

 

Three Months Ended September 30, 2014

 

 

Three Months Ended September 30, 2013

 

 

 

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

 

$

(4

)

$

 

$

(17

)

$

(21

)

 

$

109

 

$

 

$

(91

)

$

18

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Facilities segment revenues

 

 

 

 

 

 

(2

)

 

 

(2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Field operating costs

 

 

 

(2

)

(2

)

 

 

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Ra