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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended March 31, 2016

 

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 May 2, 2016, there were 397,730,991 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 March 31, 2016 and December 31, 2015

3

Condensed Consolidated Statements of Operations: For the three months ended March 31, 2016 and 2015

4

Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2016 and 2015

5

Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the three months ended March 31, 2016 and 2015

5

Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2016 and 2015

6

Condensed Consolidated Statements of Changes in Partners’ Capital: For the three months ended March 31, 2016 and 2015

7

Notes to the Condensed Consolidated Financial Statements:

 

1. Organization and Basis of Consolidation and Presentation

8

2. Recent Accounting Pronouncements

9

3. Net Income Per Common Unit

9

4. Accounts Receivable, Net

10

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

11

6. Debt

12

7. Partners’ Capital and Distributions

13

8. Derivatives and Risk Management Activities

14

9. Related Party Transactions

20

10. Commitments and Contingencies

21

11. Operating Segments

26

12. Acquisitions and Dispositions

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

44

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.                                                         UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

 

 

 

March 31,

 

December 31,

 

 

 

2016

 

2015

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

36

 

$

27

 

Trade accounts receivable and other receivables, net

 

1,549

 

1,785

 

Inventory

 

877

 

916

 

Other current assets

 

318

 

241

 

Total current assets

 

2,780

 

2,969

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

15,875

 

15,654

 

Accumulated depreciation

 

(2,205

)

(2,180

)

Property and equipment, net

 

13,670

 

13,474

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

2,405

 

2,405

 

Investments in unconsolidated entities

 

2,097

 

2,027

 

Linefill and base gas

 

899

 

898

 

Long-term inventory

 

112

 

129

 

Other long-term assets, net

 

334

 

386

 

Total assets

 

$

22,297

 

$

22,288

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

1,979

 

$

2,038

 

Short-term debt

 

715

 

999

 

Other current liabilities

 

369

 

370

 

Total current liabilities

 

3,063

 

3,407

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discounts and debt issuance costs

 

9,126

 

9,698

 

Other long-term debt

 

27

 

677

 

Other long-term liabilities and deferred credits

 

710

 

567

 

Total long-term liabilities

 

9,863

 

10,942

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 10)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Series A preferred unitholders (61,030,127 units outstanding)

 

1,509

 

 

Common unitholders (397,730,991 and 397,727,624 units outstanding, respectively)

 

7,474

 

7,580

 

General partner

 

330

 

301

 

Total partners’ capital excluding noncontrolling interests

 

9,313

 

7,881

 

Noncontrolling interests

 

58

 

58

 

Total partners’ capital

 

9,371

 

7,939

 

Total liabilities and partners’ capital

 

$

22,297

 

$

22,288

 

 

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

 

3



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 

 

 

Three Months Ended
March 31,

 

 

 

2016

 

2015

 

 

 

(unaudited)

 

REVENUES

 

 

 

 

 

Supply and Logistics segment revenues

 

$

3,819

 

$

5,632

 

Transportation segment revenues

 

154

 

185

 

Facilities segment revenues

 

138

 

125

 

Total revenues

 

4,111

 

5,942

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

Purchases and related costs

 

3,348

 

5,042

 

Field operating costs

 

300

 

346

 

General and administrative expenses

 

67

 

78

 

Depreciation and amortization

 

114

 

104

 

Total costs and expenses

 

3,829

 

5,570

 

 

 

 

 

 

 

OPERATING INCOME

 

282

 

372

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

Equity earnings in unconsolidated entities

 

47

 

37

 

Interest expense (net of capitalized interest of $13 and $14, respectively)

 

(112

)

(105

)

Other income/(expense), net

 

5

 

(4

)

 

 

 

 

 

 

INCOME BEFORE TAX

 

222

 

300

 

Current income tax expense

 

(31

)

(42

)

Deferred income tax benefit

 

12

 

26

 

 

 

 

 

 

 

NET INCOME

 

203

 

284

 

Net income attributable to noncontrolling interests

 

(1

)

(1

)

NET INCOME ATTRIBUTABLE TO PAA

 

$

202

 

$

283

 

 

 

 

 

 

 

NET INCOME PER COMMON UNIT (NOTE 3):

 

 

 

 

 

Net income attributable to common unitholders — Basic

 

$

28

 

$

136

 

Basic weighted average common units outstanding

 

398

 

383

 

Basic net income per common unit

 

$

0.07

 

$

0.36

 

 

 

 

 

 

 

Net income attributable to common unitholders — Diluted

 

$

28

 

$

136

 

Diluted weighted average common units outstanding

 

399

 

385

 

Diluted net income per common unit

 

$

0.07

 

$

0.35

 

 

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

 

4



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

 

 

Three Months Ended
March 31,

 

 

 

2016

 

2015

 

 

 

(unaudited)

 

Net income

 

$

203

 

$

284

 

Other comprehensive income/(loss)

 

118

 

(376

)

Comprehensive income/(loss)

 

321

 

(92

)

Comprehensive income attributable to noncontrolling interests

 

(1

)

(1

)

Comprehensive income/(loss) attributable to PAA

 

$

320

 

$

(93

)

 

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, 2015

 

$

(203

)

$

(878

)

$

(1,081

)

 

 

 

 

 

 

 

 

Reclassification adjustments

 

1

 

 

1

 

Deferred loss on cash flow hedges

 

(90

)

 

(90

)

Currency translation adjustments

 

 

207

 

207

 

Total period activity

 

(89

)

207

 

118

 

Balance at March 31, 2016

 

$

(292

)

$

(671

)

$

(963

)

 

 

 

Derivative

 

Translation

 

 

 

 

 

Instruments

 

Adjustments

 

Total

 

 

 

(unaudited)

 

Balance at December 31, 2014

 

$

(159

)

$

(308

)

$

(467

)

 

 

 

 

 

 

 

 

Reclassification adjustments

 

(6

)

 

(6

)

Deferred loss on cash flow hedges

 

(72

)

 

(72

)

Currency translation adjustments

 

 

(298

)

(298

)

Total period activity

 

(78

)

(298

)

(376

)

Balance at March 31, 2015

 

$

(237

)

$

(606

)

$

(843

)

 

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

 

5



Table of Contents

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

2015

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

203

 

$

284

 

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

 

 

 

 

 

Depreciation and amortization

 

114

 

104

 

Equity-indexed compensation expense

 

4

 

19

 

Inventory valuation adjustments

 

3

 

24

 

Deferred income tax benefit

 

(12

)

(26

)

Gain on foreign currency revaluation

 

(3

)

(27

)

Equity earnings in unconsolidated entities

 

(47

)

(37

)

Distributions from unconsolidated entities

 

52

 

54

 

Other

 

3

 

(6

)

Changes in assets and liabilities, net of acquisitions

 

318

 

343

 

Net cash provided by operating activities

 

635

 

732

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions

 

(85

)

(64

)

Investments in unconsolidated entities

 

(75

)

(65

)

Additions to property, equipment and other

 

(372

)

(441

)

Cash paid for purchases of linefill and base gas

 

 

(96

)

Proceeds from sales of assets

 

246

 

1

 

Other investing activities

 

(1

)

(1

)

Net cash used in investing activities

 

(287

)

(666

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net repayments under commercial paper program (Note 6)

 

(1,211

)

(734

)

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

 

(300

)

 

Net proceeds from the sale of Series A preferred units and associated embedded derivative (Note 7)

 

1,570

 

 

Net proceeds from the sale of common units

 

 

1,099

 

Contributions from general partner

 

33

 

22

 

Distributions paid to common unitholders (Note 7)

 

(278

)

(254

)

Distributions paid to general partner (Note 7)

 

(155

)

(136

)

Other financing activities

 

(2

)

(3

)

Net cash used in financing activities

 

(343

)

(6

)

 

 

 

 

 

 

Effect of translation adjustment on cash

 

4

 

(5

)

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

9

 

55

 

Cash and cash equivalents, beginning of period

 

27

 

403

 

Cash and cash equivalents, end of period

 

$

36

 

$

458

 

 

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

85

 

$

74

 

Income taxes, net of amounts refunded

 

$

16

 

$

11

 

 

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)

 

 

 

Limited Partners

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

Series A

 

 

 

 

 

Excluding

 

 

 

Total

 

 

 

Preferred

 

Common

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Unitholders

 

Unitholders

 

Partner

 

Interests

 

Interests

 

Capital

 

 

 

(unaudited)

 

Balance at December 31, 2015

 

$

 

$

7,580

 

$

301

 

$

7,881

 

$

58

 

$

7,939

 

Net income

 

 

55

 

147

 

202

 

1

 

203

 

Distributions

 

 

(278

)

(155

)

(433

)

(1

)

(434

)

Sale of Series A preferred units

 

1,509

 

 

33

 

1,542

 

 

1,542

 

Other comprehensive income

 

 

115

 

3

 

118

 

 

118

 

Other

 

 

2

 

1

 

3

 

 

3

 

Balance at March 31, 2016

 

$

1,509

 

$

7,474

 

$

330

 

$

9,313

 

$

58

 

$

9,371

 

 

 

 

 

 

 

 

Partners’ Capital

 

 

 

 

 

 

 

 

 

 

 

Excluding

 

 

 

Total

 

 

 

Limited Partners

 

General

 

Noncontrolling

 

Noncontrolling

 

Partners’

 

 

 

Common Unitholders

 

Partner

 

Interests

 

Interests

 

Capital

 

 

 

(unaudited)

 

Balance at December 31, 2014

 

$

7,793

 

$

340

 

$

8,133

 

$

58

 

$

8,191

 

Net income

 

138

 

145

 

283

 

1

 

284

 

Distributions

 

(254

)

(136

)

(390

)

(1

)

(391

)

Sale of common units

 

1,099

 

22

 

1,121

 

 

1,121

 

Other comprehensive loss

 

(369

)

(7

)

(376

)

 

(376

)

Other

 

6

 

1

 

7

 

 

7

 

Balance at March 31, 2015

 

$

8,413

 

$

365

 

$

8,778

 

$

58

 

$

8,836

 

 

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. (“PAA”) 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,” “we,” “us,” “our,” “ours” and similar terms refer to PAA 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. 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: Transportation, Facilities and Supply and Logistics. See Note 11 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. (“PAGP”) is the sole member of GP LLC, and at March 31, 2016, owned an approximate 43% 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/(loss)

Bcf

 

=

 

Billion cubic feet

Btu

 

=

 

British thermal unit

CAD

 

=

 

Canadian dollar

DERs

 

=

 

Distribution equivalent rights

EPA

 

=

 

United States Environmental Protection Agency

FASB

 

=

 

Financial Accounting Standards Board

GAAP

 

=

 

Generally accepted accounting principles in the United States

ICE

 

=

 

Intercontinental Exchange

LIBOR

 

=

 

London Interbank Offered Rate

LTIP

 

=

 

Long-term incentive plan

Mcf

 

=

 

Thousand cubic feet

MLP

 

=

 

Master limited partnership

NGL

 

=

 

Natural gas liquids, including ethane, propane and butane

NYMEX

 

=

 

New York Mercantile Exchange

Oxy

 

=

 

Occidental Petroleum Corporation or its subsidiaries

PLA

 

=

 

Pipeline loss allowance

SEC

 

=

 

United States Securities and Exchange Commission

USD

 

=

 

United States dollar

WTI

 

=

 

West Texas Intermediate

 

8



Table of Contents

 

Basis of Consolidation and Presentation

 

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2015 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. 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, and certain reclassifications have been made to information from previous years to conform to the current presentation. Such reclassifications include $3 million reclassified from “Depreciation and amortization” to “Interest expense, net” in our accompanying Condensed Consolidated Statements of Operations for the three months ended March 31, 2015 due to the retrospective application of revised debt issuance costs guidance issued by the FASB, which we adopted during the fourth quarter of 2015. These reclassifications do not affect net income attributable to PAA. The condensed consolidated balance sheet data as of December 31, 2015 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2016 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

 

Except as discussed below and in our 2015 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2016 that are of significance or potential significance to us.

 

In February 2016, the FASB issued guidance that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months, including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

In March 2016, the FASB issued guidance to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance will become effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We expect to adopt this guidance on January 1, 2017, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

Note 3—Net Income Per Common Unit

 

Basic and diluted net income per common unit is determined pursuant to the two-class method for MLPs as prescribed in FASB guidance. The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, limited partners 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 preferred unitholders, 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.

 

We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting the amount allocated to the preferred unitholders, the general partner’s interest, IDRs and participating securities) by the basic and diluted weighted-average number of common 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 common unit is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2016 as the effect was antidilutive. See Note 7 to our Condensed Consolidated Financial Statements for additional information regarding our Series A preferred units. 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 common unit repurchase based on the remaining unamortized fair value, as

 

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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 2015 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 common unit (in millions, except per unit data):

 

 

 

Three Months Ended
March 31,

 

 

 

2016

 

2015

 

Basic Net Income per Common Unit

 

 

 

 

 

Net income attributable to PAA

 

$

202

 

$

283

 

Less: Distributions to Series A preferred units (1)

 

(23

)

 

Less: Distributions to general partner (1)

 

(155

)

(148

)

Less: Distributions to participating securities (1)

 

(1

)

(2

)

Less: Undistributed loss allocated to general partner (1)

 

5

 

3

 

Net income attributable to common unitholders in accordance with application of the two-class method for MLPs

 

$

28

 

$

136

 

 

 

 

 

 

 

Basic weighted average common units outstanding

 

398

 

383

 

 

 

 

 

 

 

Basic net income per common unit

 

$

0.07

 

$

0.36

 

 

 

 

 

 

 

Diluted Net Income per Common Unit

 

 

 

 

 

Net income attributable to PAA

 

$

202

 

$

283

 

Less: Distributions to Series A preferred units (1)

 

(23

)

 

Less: Distributions to general partner (1)

 

(155

)

(148

)

Less: Distributions to participating securities (1)

 

(1

)

(2

)

Less: Undistributed loss allocated to general partner (1)

 

5

 

3

 

Net income attributable to common unitholders in accordance with application of the two-class method for MLPs

 

$

28

 

$

136

 

 

 

 

 

 

 

Basic weighted average common units outstanding

 

398

 

383

 

Effect of dilutive securities: Weighted average LTIP units

 

1

 

2

 

Diluted weighted average common units outstanding

 

399

 

385

 

 

 

 

 

 

 

Diluted net income per common unit

 

$

0.07

 

$

0.35

 

 


(1)                                     We calculate net income attributable to common unitholders 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, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement and as further prescribed under the two-class method.

 

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 our 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 common unit. If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of our partnership agreement, basic and diluted net income per common unit as reflected in the table above would not have been impacted, as we did not have undistributed earnings for any of the periods presented.

 

Note 4—Accounts Receivable, Net

 

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open 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 March 31, 2016 and December 31, 2015, we had received $52 million and $88 million, respectively, of advance cash payments from third parties to mitigate credit risk.

 

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We also received $26 million and $36 million as of March 31, 2016 and December 31, 2015, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also 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 March 31, 2016 and December 31, 2015, substantially all of our trade 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 at both March 31, 2016 and December 31, 2015. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

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):

 

 

 

March 31, 2016

 

 

December 31, 2015

 

 

 

Volumes

 

Unit of
Measure

 

Carrying
Value

 

Price/
Unit 
(1)

 

 

Volumes

 

Unit of
Measure

 

Carrying
Value

 

Price/
Unit 
(1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

21,073

 

barrels

 

$

711

 

$

33.74

 

 

16,345

 

barrels

 

$

608

 

$

37.20

 

NGL

 

6,512

 

barrels

 

102

 

$

15.66

 

 

13,907

 

barrels

 

218

 

$

15.68

 

Natural gas

 

17,150

 

Mcf

 

34

 

$

1.98

 

 

22,080

 

Mcf

 

53

 

$

2.40

 

Other

 

N/A

 

 

 

30

 

N/A

 

 

N/A

 

 

 

37

 

N/A

 

Inventory subtotal

 

 

 

 

 

877

 

 

 

 

 

 

 

 

916

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

12,060

 

barrels

 

711

 

$

58.96

 

 

12,298

 

barrels

 

713

 

$

57.98

 

NGL

 

1,348

 

barrels

 

47

 

$

34.87

 

 

1,348

 

barrels

 

44

 

$

32.64

 

Natural gas

 

30,812

 

Mcf

 

141

 

$

4.58

 

 

30,812

 

Mcf

 

141

 

$

4.58

 

Linefill and base gas subtotal

 

 

 

 

 

899

 

 

 

 

 

 

 

 

898

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

3,333

 

barrels

 

92

 

$

27.60

 

 

3,417

 

barrels

 

106

 

$

31.02

 

NGL

 

1,652

 

barrels

 

20

 

$

12.11

 

 

1,652

 

barrels

 

23

 

$

13.92

 

Long-term inventory subtotal

 

 

 

 

 

112

 

 

 

 

 

 

 

 

129

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

1,888

 

 

 

 

 

 

 

 

$

1,943

 

 

 

 


(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. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $24 million during the three months ended March 31, 2015 primarily related to the writedown of our NGL inventory due to declines in prices. The loss was substantially offset by a portion of the derivative mark-to-market gain that was recognized in the fourth quarter of 2014. See Note 8 for discussion of our derivative and risk management activities.

 

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Note 6—Debt

 

Debt consisted of the following (in millions):

 

 

 

March 31,

 

December 31,

 

 

 

2016

 

2015

 

SHORT-TERM DEBT

 

 

 

 

 

Commercial paper notes, bearing a weighted-average interest rate of 0.9% and 1.1%, respectively (1)

 

$

137

 

$

696

 

Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.4% (1)

 

 

300

 

Senior notes:

 

 

 

 

 

5.88% senior notes due August 2016

 

175

 

 

6.13% senior notes due January 2017

 

400

 

 

Other

 

3

 

3

 

Total short-term debt

 

715

 

999

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

Senior notes, net of unamortized discounts and debt issuance costs of $74 and $77, respectively

 

9,126

 

9,698

 

Commercial paper notes, bearing a weighted-average interest rate of 0.9% and 1.1%, respectively

 

23

 

672

 

Other

 

4

 

5

 

Total long-term debt

 

9,153

 

10,375

 

Total debt (2)

 

$

9,868

 

$

11,374

 

 


(1)                                     We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2016 and December 31, 2015, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

 

(2)                                     Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.8 billion as of both March 31, 2016 and December 31, 2015. We estimated the aggregate fair value of these notes as of March 31, 2016 and December 31, 2015 to be approximately $9.0 billion and $8.6 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 the end of the reporting period. 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 in Level 2 of the fair value hierarchy.

 

Borrowings and Repayments

 

Total borrowings under our credit facilities and commercial paper program for the three months ended March 31, 2016 and 2015 were approximately $10.8 billion and $7.0 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $12.3 billion and $7.7 billion for the three months ended March 31, 2016 and 2015, 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, derivative transactions and construction activities. At March 31, 2016 and December 31, 2015, we had outstanding letters of credit of $45 million and $46 million, respectively.

 

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Note 7—Partners’ Capital and Distributions

 

Units Outstanding

 

The following tables present the activity for our Series A preferred units and common units:

 

 

 

Limited Partners

 

 

 

Preferred Units

 

Common Units

 

Outstanding at December 31, 2015

 

 

397,727,624

 

Sale of Series A preferred units

 

61,030,127

 

 

Issuance of common units under LTIP

 

 

3,367

 

Outstanding at March 31, 2016

 

61,030,127

 

397,730,991

 

 

 

 

Limited Partners

 

 

 

Common Units

 

Outstanding at December 31, 2014

 

375,107,793

 

Sale of common units

 

22,133,904

 

Outstanding at March 31, 2015

 

397,241,697

 

 

Equity Offerings

 

Series A Preferred Unit Offering. In January 2016, we completed the private placement of approximately 61.0 million Series A preferred units representing limited partner interests in us for a cash purchase price of $26.25 per unit (the “Issue Price”).

 

The Series A preferred units are a new class of equity security that ranks senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units will receive cumulative quarterly distributions, subject to customary antidilution adjustments, equal to an annual rate of 8% of the Issue Price ($2.10 per unit annualized). With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we may elect to pay distributions on the Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, we must pay distributions on the Series A preferred units in cash. Our general partner will be entitled to participate in cash distributions on the Series A preferred units equal to its 2% general partner interest.

 

The purchasers may convert their Series A preferred units, generally on a one-for-one basis and subject to customary antidilution adjustments, at any time after the second anniversary of the issuance date (or prior to a liquidation), in whole or in part, subject to certain minimum conversion amounts. We may convert the Series A preferred units at any time (but not more often than once per quarter) after the third anniversary of the issuance date, in whole or in part, subject to certain minimum conversion amounts, if the closing price of our common units is greater than 150% of the Issue Price for the preceding 20 trading days. The Series A preferred units will vote on an as-converted basis with our common units and will have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units to common units at the then applicable conversion rate.

 

For a period of 30 days following (a) the fifth anniversary of the issuance date of the Series A preferred units and (b) each subsequent anniversary of the issuance date, the holders of the Series A preferred units, acting by majority vote, may make a one-time election to reset the distribution rate to equal the then applicable rate of the ten-year U.S. Treasury plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative. See Note 8 for additional information. If the holders of the Series A preferred units have exercised the Preferred Distribution Rate Reset Option, then, at any time following 30 days after the sixth anniversary of the issuance date, we may redeem all or any portion of the outstanding Series A preferred units in exchange for cash, common units (valued at 95% of the volume-weighted average price of the common units for a trading day period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110% of the Issue Price, plus any accrued and unpaid distributions.

 

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Distributions

 

Cash Distributions. The following table details the distributions paid in cash during or pertaining to the first three months of 2016, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):

 

 

 

 

 

Distributions Paid

 

 

Distributions per

 

Date Declared

 

Distribution Date

 

Common Unitholders

 

General Partner

 

Total

 

 

common unit

 

April 7, 2016

 

May 13, 2016 (1)

 

$

278

 

$

155

 

$

433

 

 

$

0.70

 

January 12, 2016

 

February 12, 2016

 

$

278

 

$

155

 

$

433

 

 

$

0.70

 

 


(1)                                  Payable to unitholders of record at the close of business on April 29, 2016 for the period January 1, 2016 through March 31, 2016.

 

In-Kind Distributions. On May 13, 2016, we will issue 858,439 additional Series A preferred units in lieu of a cash distribution of $23 million. Such distribution is prorated for the period beginning on January 28, 2016, the issuance date of the Series A preferred units, through March 31, 2016 and will be issued to Series A preferred unitholders of record as of April 29, 2016. Since the May 13, 2016 Series A preferred unit distribution was declared as payment-in-kind, this distribution payable was accrued to partners’ capital as of March 31, 2016 and thus had no net impact on the Series A preferred unitholders’ capital account.

 

Noncontrolling Interests in Subsidiaries

 

As of March 31, 2016, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

 

Note 8—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 throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions.

 

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 March 31, 2016, net derivative positions related to these activities included:

 

·                  An average of 146,300 barrels per day net long position (total of 4.4 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2016 to match monthly average pricing.

 

·                  A net short time spread position averaging 10,000 barrels per day (total of 4.3 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2017.

 

·                  An average of 2,600 barrels per day (total of 1.2 million barrels) of crude oil grade spread positions through June 2017. These derivatives allow us to lock in grade basis differentials.

 

·                  A net short position of 13.9 Bcf through April 2017 related to anticipated sales of natural gas inventory and base gas requirements.

 

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·                  A net short position of 25.8 million barrels through December 2018 related to anticipated net sales of our crude oil and NGL inventory.

 

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of March 31, 2016, our material PLA hedges included a long call option position of 1.4 million barrels through December 2018.

 

Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and 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 March 31, 2016, we had a long natural gas position of 14.0 Bcf through December 2016, a short propane position of 2.7 million barrels through December 2016, a short butane position of 0.8 million barrels through December 2016 and a short WTI position of 0.3 million barrels through December 2016. In addition, we had a long power position of 0.4 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2018.

 

Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.

 

Interest Rate Risk Hedging

 

We use interest rate derivatives to hedge interest rate risk associated with anticipated and outstanding interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. As of March 31, 2016, AOCI includes deferred losses of $270 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges. 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 interest payments through 2049. The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2016 (notional amounts in millions):

 

Hedged Transaction

 

Number and Types of
Derivatives Employed

 

Notional
Amount

 

Expected
Termination Date

 

Average Rate
Locked

 

Accounting
Treatment

 

Anticipated interest payments

 

8 forward starting swaps (30-year)

 

$

200

 

6/15/2016

 

3.06

%

Cash flow hedge

 

Anticipated interest payments

 

8 forward starting swaps (30-year)

 

$

200

 

6/15/2017

 

3.14

%

Cash flow hedge

 

Anticipated interest payments

 

8 forward starting swaps (30-year)

 

$

200

 

6/15/2018

 

3.20

%

Cash flow hedge

 

Anticipated interest payments

 

8 forward starting swaps (30-year)

 

$

200

 

6/14/2019

 

2.83

%

Cash flow hedge

 

 

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 March 31, 2016, our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

 

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The following table summarizes our open forward exchange contracts as of March 31, 2016 (in millions):

 

 

 

 

 

USD

 

CAD

 

Average Exchange Rate
USD to CAD

 

Forward exchange contracts that exchange CAD for USD:

 

 

 

 

 

 

 

 

 

 

 

2016

 

$

147

 

$

191

 

$1.00 - $1.30

 

 

 

 

 

 

 

 

 

 

 

Forward exchange contracts that exchange USD for CAD:

 

 

 

 

 

 

 

 

 

 

 

2016

 

$

228

 

$

302

 

$1.00 - $1.33

 

 

Preferred Distribution Rate Reset Option

 

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. At March 31, 2016, the fair value of this embedded derivative was a liability of approximately $60 million. See Note 7 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option.

 

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 classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

 

A summary of the impact of our derivative activities recognized in earnings is as follows (in millions):

 

 

 

Three Months Ended March 31, 2016

 

 

Three Months Ended March 31, 2015

 

Location of Gain/(Loss)

 

Derivatives in
Hedging
Relationships

 

Derivatives
Not Designated
as a Hedge

 

Total

 

 

Derivatives in
Hedging
Relationships

 

Derivatives
Not Designated
as a Hedge

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

1

 

$

31

 

$

32

 

 

$

7

 

$

(34

)

$

(27

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation segment revenues

 

 

2

 

2

 

 

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Field operating costs

 

 

(2

)

(2

)

 

 

(4

)

(4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

(2

)

 

(2

)

 

(1

)

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

 

6

 

6

 

 

 

(17

)

(17

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

(1

)

$

37

 

$

36

 

 

$

6

 

$

(53

)

$

(47

)

 

16



Table of Contents

 

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2016 (in millions):

 

 

 

Asset Derivatives

 

Liability Derivatives

 

 

 

Balance Sheet

 

Fair

 

Balance Sheet

 

Fair

 

 

 

Location

 

Value

 

Location

 

Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

3

 

 

Other current assets

 

$

(2

)

 

 

 

 

 

 

 

 

 

 

 

Interest rate derivatives

 

 

 

 

 

 

Other current liabilities

 

(41

)

 

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(97

)

Total derivatives designated as hedging instruments

 

 

 

$

3

 

 

 

 

$

(140

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

170

 

 

Other current assets

 

$

(78

)

 

 

Other current liabilities

 

1

 

 

Other current liabilities

 

(13

)

 

 

Other long-term liabilities and deferred credits

 

2

 

 

Other long-term liabilities and deferred credits

 

(3

)

 

 

 

 

 

 

 

 

 

 

 

Foreign currency derivatives

 

Other current assets

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred Distribution Rate Reset Option

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(60

)

Total derivatives not designated as hedging instruments

 

 

 

$

178

 

 

 

 

$

(154

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

181

 

 

 

 

$

(294

)

 

17



Table of Contents

 

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions):

 

 

 

Asset Derivatives

 

Liability Derivatives

 

 

 

Balance Sheet

 

Fair

 

Balance Sheet

 

Fair

 

 

 

Location

 

Value

 

Location

 

Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

4

 

 

Other current assets

 

$

(2

)

 

 

 

 

 

 

 

 

 

 

 

Interest rate derivatives

 

Other long-term assets, net

 

1

 

 

Other current liabilities

 

(17

)

 

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(33

)

Total derivatives designated as hedging instruments

 

 

 

$

5

 

 

 

 

$

(52

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

265

 

 

Other current assets

 

$

(35

)

 

 

Other long-term assets, net

 

10

 

 

Other long-term assets, net

 

(1

)

 

 

 

 

 

 

 

Other current liabilities

 

(13

)

 

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

Foreign currency derivatives

 

 

 

 

 

 

Other current liabilities

 

(8

)

Total derivatives not designated as hedging instruments

 

 

 

$

275

 

 

 

 

$

(58

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

280

 

 

 

 

$

(110

)

 

Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

 

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of March 31, 2016, we had a net broker payable of $17 million (consisting of initial margin of $70 million reduced by $87 million of variation margin that had been returned to us). As of December 31, 2015, we had a net broker payable of $156 million (consisting of initial margin of $91 million reduced by $247 million of variation margin that had been returned to us).

 

18



Table of Contents

 

The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions):

 

 

 

March 31, 2016

 

December 31, 2015

 

 

 

Derivative

 

Derivative

 

Derivative

 

Derivative

 

 

 

Asset Positions

 

Liability Positions

 

Asset Positions

 

Liability Positions

 

Netting Adjustments:

 

 

 

 

 

 

 

 

 

 

Gross position - asset/(liability)

 

$

181

 

$

(294

)

 

$

280

 

$

(110

)

Netting adjustment

 

(83

)

83

 

 

(38

)

38

 

Cash collateral received

 

(17

)

 

 

(156

)

 

Net position - asset/(liability)

 

$

81

 

$

(211

)

 

$

86

 

$

(72

)

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Location After Netting Adjustments:

 

 

 

 

 

 

 

 

 

 

Other current assets

 

$

81

 

$

 

 

$

76

 

$

 

Other long-term assets, net

 

 

 

 

10

 

 

Other current liabilities

 

 

(53

)

 

 

(38

)

Other long-term liabilities and deferred credits

 

 

(158

)

 

 

(34

)

 

 

$

81

 

$

(211

)

 

$

86

 

$

(72

)

 

As of March 31, 2016, there was a net loss of $292 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at March 31, 2016, we expect to reclassify a net loss of $5 million to earnings in the next twelve months. The remaining deferred loss of $287 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of March 31, 2016; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

 

The following table summarizes the net deferred gain/(loss) recognized in AOCI for derivatives (in millions):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

2015

 

Commodity derivatives, net

 

$

 

$

3

 

Interest rate derivatives, net

 

(90

)

(75

)

Total

 

$

(90

)

$

(72

)

 

At March 31, 2016 and December 31, 2015, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.

 

Recurring Fair Value Measurements

 

Derivative Financial Assets and Liabilities

 

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

 

 

 

Fair Value as of March 31, 2016

 

Fair Value as of December 31, 2015

 

Recurring Fair Value Measures (1)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Commodity derivatives

 

$

62

 

$

17

 

$

1

 

$

80

 

 

$

126

 

$

90

 

$

11

 

$

227

 

Interest rate derivatives

 

 

(138

)

 

(138

)

 

 

(49

)

 

(49

)

Foreign currency derivatives

 

 

5

 

 

5

 

 

 

(8

)

 

(8

)

Preferred Distribution Rate Reset Option

 

 

 

(60

)

(60

)

 

 

 

 

 

Total net derivative asset/(liability)

 

$

62

 

$

(116

)

$

(59

)

$

(113

)

 

$

126

 

$

33

 

$

11

 

$

170

 

 


(1)                                     Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

 

19



Table of Contents

 

Level 1

 

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets.

 

Level 2

 

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs.

 

Level 3

 

Level 3 of the fair value hierarchy includes certain physical commodity contracts and the Preferred Distribution Rate Reset Option contained in our Series A preferred unit offering classified as an embedded derivative.

 

The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues.

 

The fair value of the embedded derivative feature contained in our Series A preferred units is based on a valuation model that estimates the future fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our future common unit price, future ten-year U.S. treasury rates, future default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations as “Other income/(expense), net.”

 

To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur.

 

Rollforward of Level 3 Net Asset/(Liability)

 

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

2015

 

Beginning Balance

 

$

11

 

$

15

 

Losses for the period included in earnings

 

(1