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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, 2015

 

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 1, 2015, there were 397,241,697 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, 2015 and December 31, 2014

 

3

 

Condensed Consolidated Statements of Operations: For the three months ended March 31, 2015 and 2014

 

4

 

Condensed Consolidated Statements of Comprehensive Income / (Loss): For the three months ended March 31, 2015  and 2014

 

5

 

Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income / (Loss): For the three months ended March 31, 2015 and 2014

 

5

 

Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2015 and 2014

 

6

 

Condensed Consolidated Statements of Changes in Partners’ Capital: For the three months ended March 31, 2015 and 2014

 

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 Limited Partner Unit

 

10

 

4. Accounts Receivable

 

11

 

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

 

12

 

6. Debt

 

13

 

7. Partners’ Capital and Distributions

 

14

 

8. Derivatives and Risk Management Activities

 

14

 

9. Equity-Indexed Compensation Plans

 

21

 

10. Commitments and Contingencies

 

22

 

11. Operating Segments

 

23

 

12. Related Party Transactions

 

24

 

 

 

 

 

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

 

25

 

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

41

 

Item 4. CONTROLS AND PROCEDURES

 

42

 

 

 

 

 

PART II. OTHER INFORMATION

 

 

 

Item 1. LEGAL PROCEEDINGS

 

43

 

Item 1A. RISK FACTORS

 

43

 

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

 

43

 

Item 3. DEFAULTS UPON SENIOR SECURITIES

 

43

 

Item 4. MINE SAFETY DISCLOSURES

 

43

 

Item 5. OTHER INFORMATION

 

43

 

Item 6. EXHIBITS

 

43

 

SIGNATURES

 

44

 

 

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,

 

 

 

2015

 

2014

 

 

 

(unaudited)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

458

 

$

403

 

Trade accounts receivable and other receivables, net

 

1,817

 

2,615

 

Inventory

 

929

 

891

 

Other current assets

 

249

 

270

 

Total current assets

 

3,453

 

4,179

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

14,436

 

14,178

 

Accumulated depreciation

 

(1,952

)

(1,906

)

Property and equipment, net

 

12,484

 

12,272

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

Goodwill

 

2,435

 

2,465

 

Investments in unconsolidated entities

 

1,784

 

1,735

 

Linefill and base gas

 

960

 

930

 

Long-term inventory

 

149

 

186

 

Other long-term assets, net

 

459

 

489

 

Total assets

 

$

21,724

 

$

22,256

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

2,491

 

$

2,986

 

Short-term debt

 

553

 

1,287

 

Other current liabilities

 

487

 

482

 

Total current liabilities

 

3,531

 

4,755

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

Senior notes, net of unamortized discount of $17 and $18, respectively

 

8,758

 

8,757

 

Other long-term debt

 

5

 

5

 

Other long-term liabilities and deferred credits

 

594

 

548

 

Total long-term liabilities

 

9,357

 

9,310

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 10)

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ CAPITAL

 

 

 

 

 

Common unitholders (397,241,697 and 375,107,793 units outstanding, respectively)

 

8,413

 

7,793

 

General partner

 

365

 

340

 

Total partners’ capital excluding noncontrolling interests

 

8,778

 

8,133

 

Noncontrolling interests

 

58

 

58

 

Total partners’ capital

 

8,836

 

8,191

 

Total liabilities and partners’ capital

 

$

21,724

 

$

22,256

 

 

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,

 

 

 

2015

 

2014

 

 

 

(unaudited)

 

REVENUES

 

 

 

 

 

Supply and Logistics segment revenues

 

$

5,632

 

$

11,346

 

Transportation segment revenues

 

185

 

181

 

Facilities segment revenues

 

125

 

157

 

Total revenues

 

5,942

 

11,684

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

Purchases and related costs

 

5,042

 

10,670

 

Field operating costs

 

346

 

336

 

General and administrative expenses

 

78

 

89

 

Depreciation and amortization

 

107

 

96

 

Total costs and expenses

 

5,573

 

11,191

 

 

 

 

 

 

 

OPERATING INCOME

 

369

 

493

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

Equity earnings in unconsolidated entities

 

37

 

20

 

Interest expense (net of capitalized interest of $14 and $11, respectively)

 

(102

)

(78

)

Other expense, net

 

(4

)

(2

)

 

 

 

 

 

 

INCOME BEFORE TAX

 

300

 

433

 

Current income tax expense

 

(42

)

(36

)

Deferred income tax benefit/(expense)

 

26

 

(12

)

 

 

 

 

 

 

NET INCOME

 

284

 

385

 

Net income attributable to noncontrolling interests

 

(1

)

(1

)

NET INCOME ATTRIBUTABLE TO PAA

 

$

283

 

$

384

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO PAA:

 

 

 

 

 

LIMITED PARTNERS

 

$

138

 

$

268

 

GENERAL PARTNER

 

$

145

 

$

116

 

 

 

 

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

 

$

0.36

 

$

0.74

 

 

 

 

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

 

$

0.35

 

$

0.73

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING

 

383

 

360

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING

 

385

 

363

 

 

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 / (LOSS)

(in millions)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2015

 

2014

 

 

 

(unaudited)

 

Net income

 

$

284

 

$

385

 

Other comprehensive loss

 

(376

)

(136

)

Comprehensive income/(loss)

 

(92

)

249

 

Comprehensive income attributable to noncontrolling interests

 

(1

)

(1

)

Comprehensive income/(loss) attributable to PAA

 

$

(93

)

$

248

 

 

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, 2014

 

$

(159

)

$

(308

)

$

(467

)

 

 

 

 

 

 

 

 

Reclassification adjustments

 

(6

)

 

(6

)

Deferred loss on cash flow hedges, net of tax

 

(72

)

 

(72

)

Currency translation adjustments

 

 

(298

)

(298

)

Total period activity

 

(78

)

(298

)

(376

)

Balance at March 31, 2015

 

$

(237

)

$

(606

)

$

(843

)

 

 

 

Derivative

 

Translation

 

 

 

 

 

Instruments

 

Adjustments

 

Total

 

 

 

(unaudited)

 

Balance at December 31, 2013

 

$

(77

)

$

(20

)

$

(97

)

 

 

 

 

 

 

 

 

Reclassification adjustments

 

20

 

 

20

 

Deferred loss on cash flow hedges, net of tax

 

(32

)

 

(32

)

Currency translation adjustments

 

 

(124

)

(124

)

Total period activity

 

(12

)

(124

)

(136

)

Balance at March 31, 2014

 

$

(89

)

$

(144

)

$

(233

)

 

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,

 

 

 

2015

 

2014

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

284

 

$

385

 

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

 

 

 

 

 

Depreciation and amortization

 

107

 

96

 

Equity-indexed compensation expense

 

19

 

34

 

Inventory valuation adjustments

 

24

 

37

 

Deferred income tax (benefit)/expense

 

(26

)

12

 

(Gain)/loss on foreign currency revaluation

 

(27

)

5

 

Equity earnings in unconsolidated entities

 

(37

)

(20

)

Distributions from unconsolidated entities

 

54

 

25

 

Other

 

(9

)

(6

)

Changes in assets and liabilities, net of acquisitions

 

343

 

254

 

Net cash provided by operating activities

 

732

 

822

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid in connection with acquisitions, net of cash acquired

 

(64

)

 

Additions to property, equipment and other

 

(441

)

(468

)

Investment in unconsolidated entities

 

(65

)

(26

)

Cash received for sales of linefill and base gas

 

 

11

 

Cash paid for purchases of linefill and base gas

 

(96

)

(44

)

Proceeds from sales of assets

 

1

 

2

 

Other investing activities

 

(1

)

1

 

Net cash used in investing activities

 

(666

)

(524

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Net repayments under commercial paper program (Note 6)

 

(734

)

(128

)

Net proceeds from the issuance of common units (Note 7)

 

1,099

 

148

 

Contributions from general partner

 

22

 

3

 

Distributions paid to common unitholders (Note 7)

 

(254

)

(221

)

Distributions paid to general partner (Note 7)

 

(136

)

(107

)

Distributions paid to noncontrolling interests

 

(1

)

(1

)

Other financing activities

 

(2

)

(1

)

Net cash used in financing activities

 

(6

)

(307

)

 

 

 

 

 

 

Effect of translation adjustment on cash

 

(5

)

(2

)

 

 

 

 

 

 

Net increase/(decrease) in cash and cash equivalents

 

55

 

(11

)

Cash and cash equivalents, beginning of period

 

403

 

41

 

Cash and cash equivalents, end of period

 

$

458

 

$

30

 

 

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

74

 

$

78

 

Income taxes, net of amounts refunded

 

$

11

 

$

66

 

 

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, 2014

 

375.1

 

$

7,793

 

$

340

 

$

8,133

 

$

58

 

$

8,191

 

Net income

 

 

138

 

145

 

283

 

1

 

284

 

Distributions

 

 

(254

)

(136

)

(390

)

(1

)

(391

)

Issuance of common units

 

22.1

 

1,099

 

22

 

1,121

 

 

1,121

 

Equity-indexed compensation expense

 

 

8

 

1

 

9

 

 

9

 

Distribution equivalent right payments

 

 

(2

)

 

(2

)

 

(2

)

Other comprehensive loss

 

 

(369

)

(7

)

(376

)

 

(376

)

Balance at March 31, 2015

 

397.2

 

$

8,413

 

$

365

 

$

8,778

 

$

58

 

$

8,836

 

 

 

 

 

 

 

 

 

 

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

 

 

268

 

116

 

384

 

1

 

385

 

Distributions

 

 

(221

)

(107

)

(328

)

(1

)

(329

)

Issuance of common units

 

2.8

 

148

 

3

 

151

 

 

151

 

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

 

0.1

 

(2

)

 

(2

)

 

(2

)

Equity-indexed compensation expense

 

 

11

 

1

 

12

 

 

12

 

Distribution equivalent right payments

 

 

(1

)

 

(1

)

 

(1

)

Other comprehensive loss

 

 

(133

)

(3

)

(136

)

 

(136

)

Balance at March 31, 2014

 

362.0

 

$

7,419

 

$

305

 

$

7,724

 

$

59

 

$

7,783

 

 

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. 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, 2015, owned an approximate 37% 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

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 2014 Annual Report on Form 10-K. The accompanying 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. These reclassifications do not affect net income attributable to PAA. The condensed consolidated balance sheet data as of December 31, 2014 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, 2015 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

 

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs in entities’ financial statements. Under this revised guidance, an entity will present such costs as a direct reduction from the related debt liability (rather than as an asset under current guidance). Additionally, amortization of the debt issuance costs will be reported as interest expense. This guidance will become effective for interim and annual periods beginning after December 15, 2015 and will be adopted retrospectively to all prior periods. Early adoption is permitted for financial statements that have not been previously issued. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance will become effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

In January 2015, as part of its initiative to reduce complexity in accounting standards, the FASB issued guidance to eliminate the concept of extraordinary items from GAAP. This guidance will become effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our financial position, results of operations or cash flows.

 

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 currently expect to adopt this guidance on January 1, 2017, and we are 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 2015, the FASB proposed a one year deferral of the effective date of this standard.

 

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. We adopted this guidance on January 1, 2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

 

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Table of Contents

 

Note 3—Net Income Per Limited Partner Unit

 

Basic and diluted net income per limited partner 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, 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.

 

We calculate 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 limited partner units plus the effect of dilutive potential limited partner 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 limited partner unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.  See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 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 months ended March 31, 2015 and 2014 (in millions, except per unit data):

 

 

 

Three Months Ended
March 31,

 

 

 

2015

 

2014

 

Basic Net Income per Limited Partner Unit

 

 

 

 

 

Net income attributable to PAA

 

$

283

 

$

384

 

Less: General partner’s incentive distribution (1)

 

(142

)

(110

)

Less: General partner 2% ownership (1)

 

(3

)

(6

)

Net income available to limited partners

 

138

 

268

 

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

 

(2

)

(2

)

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

 

$

136

 

$

266

 

 

 

 

 

 

 

Basic weighted average limited partner units outstanding

 

383

 

360

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.36

 

$

0.74

 

 

 

 

 

 

 

Diluted Net Income per Limited Partner Unit

 

 

 

 

 

Net income attributable to PAA

 

$

283

 

$

384

 

Less: General partner’s incentive distribution (1)

 

(142

)

(110

)

Less: General partner 2% ownership (1)

 

(3

)

(6

)

Net income available to limited partners

 

138

 

268

 

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

 

(2

)

(2

)

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

 

$

136

 

$

266

 

 

 

 

 

 

 

Basic weighted average limited partner units outstanding

 

383

 

360

 

Effect of dilutive securities: Weighted average LTIP units

 

2

 

3

 

Diluted weighted average limited partner units outstanding

 

385

 

363

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

0.35

 

$

0.73

 

 

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Table of Contents

 


(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.

 

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

 

 

 

March 31,

 

 

 

2015

 

2014

 

Basic net income per limited partner unit impact

 

$

 

$

(0.05

)

 

 

 

 

 

 

Diluted net income per limited partner unit impact

 

$

 

$

(0.05

)

 

Note 4—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 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, 2015 and December 31, 2014, we had received $130 million and $180 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of March 31, 2015 and December 31, 2014, we had received $12 million and $198 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. The decrease in standby letters of credit and advance cash payments from third parties as of March 31, 2015 compared to December 31, 2014 is largely due to a decrease in exposure to various customers requiring letters of credit.  Furthermore, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2015 and December 31, 2014, 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 as of both March 31, 2015 and December 31, 2014. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

 

11



 

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

 

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

 

 

 

March 31, 2015

 

December 31, 2014

 

 

 

Volumes

 

Unit of
Measure

 

Carrying
Value

 

Price/
Unit 
(1)

 

Volumes

 

Unit of
Measure

 

Carrying
Value

 

Price/
Unit 
(1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

15,351

 

barrels

 

$

686

 

$

44.69

 

 

6,465

 

barrels

 

$

304

 

$

47.02

 

NGL

 

7,277

 

barrels

 

154

 

$

21.16

 

 

13,553

 

barrels

 

454

 

$

33.50

 

Natural gas

 

10,965

 

Mcf

 

31

 

$

2.83

 

 

32,317

 

Mcf

 

102

 

$

3.16

 

Other

 

N/A

 

 

 

58

 

N/A

 

 

N/A

 

 

 

31

 

N/A

 

Inventory subtotal

 

 

 

 

 

929

 

 

 

 

 

 

 

 

891

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

12,970

 

barrels

 

777

 

$

59.91

 

 

11,810

 

barrels

 

744

 

$

63.00

 

NGL

 

1,215

 

barrels

 

48

 

$

39.51

 

 

1,212

 

barrels

 

52

 

$

42.90

 

Natural gas

 

28,612

 

Mcf

 

135

 

$

4.72

 

 

28,612

 

Mcf

 

134

 

$

4.68

 

Linefill and base gas subtotal

 

 

 

 

 

960

 

 

 

 

 

 

 

 

930

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

2,646

 

barrels

 

117

 

$

44.22

 

 

2,582

 

barrels

 

136

 

$

52.67

 

NGL

 

1,681

 

barrels

 

32

 

$

19.04

 

 

1,681

 

barrels

 

50

 

$

29.74

 

Long-term inventory subtotal

 

 

 

 

 

149

 

 

 

 

 

 

 

 

186

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

2,038

 

 

 

 

 

 

 

 

$

2,007

 

 

 

 


(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 for which the related derivatives were still open as of March 31, 2015. See Note 8 for discussion of our derivative and risk management activities. During the three months ended March 31, 2014, we recorded a charge of $37 million 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.

 

12



 

Note 6—Debt

 

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

 

 

 

March 31,

 

December 31,

 

 

 

2015

 

2014

 

SHORT-TERM DEBT

 

 

 

 

 

Commercial paper notes, bearing a weighted-average interest rate of 0.46% at December 31, 2014 (1)

 

$

 

$

734

 

Senior notes:

 

 

 

 

 

5.25% senior notes due June 2015

 

150

 

150

 

3.95% senior notes due September 2015

 

400

 

400

 

Other

 

3

 

3

 

Total short-term debt

 

553

 

1,287

 

 

 

 

 

 

 

LONG-TERM DEBT

 

 

 

 

 

Senior notes, net of unamortized discount of $17 and $18, respectively

 

8,758

 

8,757

 

Other

 

5

 

5

 

Total long-term debt

 

8,763

 

8,762

 

Total debt (2)

 

$

9,316

 

$

10,049

 

 


(1)                                     At December 31, 2014, we classified all of the borrowings under our commercial paper program as short-term as these borrowings were primarily designated as working capital borrowings, must 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 $9.3 billion as of both March 31, 2015 and December 31, 2014. We estimated the aggregate fair value of these notes as of March 31, 2015 and December 31, 2014 to be approximately $10.0 billion and $9.9 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 in Level 2 of the fair value hierarchy.

 

Credit Facilities

 

PAA senior unsecured 364-day revolving credit facility. In January 2015, we entered into a 364-day senior unsecured credit agreement with a borrowing capacity of $1.0 billion. Borrowings will accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, as defined in the agreement, in each case plus a margin based on our credit rating at the applicable time.

 

Borrowings and Repayments

 

Total borrowings under our credit agreements and commercial paper program for the three months ended March 31, 2015 and 2014 were approximately $7.0 billion and $19.2 billion, respectively. Total repayments under our credit agreements and commercial paper program were approximately $7.7 billion and $19.3 billion for the three months ended March 31, 2015 and 2014, 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 March 31, 2015 and December 31, 2014, we had outstanding letters of credit of $83 million and $87 million, respectively.

 

13



 

Note 7—Partners’ Capital and Distributions

 

Distributions

 

The following table details the distributions paid during or pertaining to the first three months of 2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):

 

 

 

 

 

Distributions Paid

 

Distributions

 

 

 

 

 

Limited

 

General Partner

 

 

 

per limited

 

Date Declared

 

Distribution Date

 

Partners

 

2%

 

Incentive

 

Total

 

partner unit

 

April 7, 2015

 

May 15, 2015(1)

 

$

272

 

$

6

 

$

142

 

$

420

 

 

$

0.6850

 

January 8, 2015

 

February 13, 2015

 

$

254

 

$

5

 

$

131

 

$

390

 

 

$

0.6750

 

 


(1)                                  Payable to unitholders of record at the close of business on May 1, 2015 for the period January 1, 2015 through March 31, 2015.

 

PAA Equity Offerings

 

Continuous Offering Program. During the three months ended March 31, 2015, we issued an aggregate of approximately 1.1 million common units under our continuous offering program, generating proceeds of $59 million, including our general partner’s proportionate capital contribution of $1 million, net of $1 million of commissions to our sales agents.

 

Underwritten Offering. In March 2015, we completed an underwritten public offering of 21.0 million common units, generating proceeds of approximately $1.1 billion, including our general partner’s proportionate capital contribution of $21 million, net of costs associated with the offering.

 

Noncontrolling Interests in Subsidiaries

 

As of March 31, 2015, 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 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 March 31, 2015, net derivative positions related to these activities included:

 

14



 

·                  An average of 233,600 barrels per day net long position (total of 7.0 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2015 to match monthly average pricing.

 

·                  A net short time spread position averaging 18,200 barrels per day (total of 7.2 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2016.

 

·                  An average of 37,500 barrels per day (total of 9.1 million barrels) of crude oil grade spread positions through December 2015. These derivatives allow us to lock in grade basis differentials.

 

·                  A net short position of 6.8 Bcf through April 2016 related to anticipated sales of natural gas inventory and base gas requirements.

 

·                  A net short position of 16.8 million barrels through March 2017 related to anticipated purchases and sales of our crude oil, NGL and refined products inventory.

 

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, 2015, we had a long natural gas position of 18.1 Bcf through December 2016, a short propane position of 3.5 million barrels through December 2016, a short butane position of 1.0 million barrels through December 2016 and a short WTI position of 0.4 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 natural gas processing and fractionation plants through December 2016.

 

To the extent they qualify and we decide to make the election, all of our commodity derivatives for which we elect hedge accounting are designated as cash flow hedges. 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 purchase and sale agreements 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 debt issuances and outstanding debt instruments.  The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks.  As of March 31, 2015, AOCI includes deferred losses of $234 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 debt issuances through 2019. The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2015 (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

 

Anticipated debt offering

 

8 forward starting swaps (30-year)

 

$

200

 

6/15/2016

 

3.06%

 

Cash flow hedge

 

Anticipated debt offering

 

8 forward starting swaps (30-year)

 

$

200

 

6/15/2017

 

3.14%

 

Cash flow hedge

 

Anticipated debt offering

 

8 forward starting swaps (30-year)

 

$

200

 

6/15/2018

 

3.20%

 

Cash flow hedge

 

Anticipated debt offering

 

8 forward starting swaps (30-year)

 

$

200

 

6/14/2019

 

2.83%

 

Cash flow hedge

 

 

15



 

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, 2015, 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 March 31, 2015 (in millions):

 

 

 

 

 

USD

 

CAD

 

Average Exchange Rate
USD to CAD

 

Forward exchange contracts that exchange CAD for USD:

 

 

 

 

 

 

 

 

 

 

 

2015

 

$

147

 

$

187

 

$1.00 - $1.27

 

 

 

2016

 

5

 

7

 

$1.00 - $1.27

 

 

 

 

 

$

152

 

$

194

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward exchange contracts that exchange USD for CAD:

 

 

 

 

 

 

 

 

 

 

 

2015

 

$

181

 

$

225

 

$1.00 - $1.24

 

 

 

2016

 

5

 

7

 

$1.00 - $1.27

 

 

 

 

 

$

186

 

$

232

 

 

 

 

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.

 

16



Table of Contents

 

A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2015 and 2014 is as follows (in millions):

 

 

 

Three Months Ended March 31, 2015

 

 

Three Months Ended March 31, 2014

 

Location of gain/(loss)

 

Derivatives in
Hedging
Relationships 
(1)

 

Derivatives
Not Designated
as a Hedge

 

Total

 

 

Derivatives in
Hedging
Relationships 
(1)

 

Derivatives
Not Designated
as a Hedge

 

Total

 

Commodity Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

$

7

 

$

(34

)

$

(27

)

 

$

(19

)

$

 

$

(19

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation segment revenues

 

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Field operating costs

 

 

(4

)

(4

)

 

 

(1

)

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(1

)

 

(1

)

 

(1

)

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supply and Logistics segment revenues

 

 

(17

)

(17

)

 

 

(9

)

(9

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

6

 

$

(53

)

$

(47

)

 

$

(20

)

$

(10

)

$

(30

)

 


(1)                                  Represents gains/(losses) on cash flow hedges reclassified from AOCI to income during the period.

 

17



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

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

Balance Sheet

 

 

 

 

Balance Sheet

 

 

 

 

 

Location

 

Fair Value

 

 

Location

 

Fair Value

 

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

18

 

 

Other long-term liabilities and deferred credits

 

$

(2

)

 

 

Other long-term liabilities and deferred credits

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate derivatives

 

 

 

 

 

 

Other current liabilities

 

(64

)

 

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(80

)

Total derivatives designated as hedging instruments

 

 

 

$

21

 

 

 

 

$

(146

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

205

 

 

Other current assets

 

$

(47

)

 

 

Other long-term assets, net

 

18

 

 

Other current liabilities

 

(40

)

 

 

Other long-term liabilities and deferred credits

 

2

 

 

Other long-term liabilities and deferred credits

 

(13

)

 

 

 

 

 

 

 

 

 

 

 

Foreign currency derivatives

 

 

 

 

 

 

Other current liabilities

 

(4

)

Total derivatives not designated as hedging instruments

 

 

 

$

225

 

 

 

 

$

(104

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

246

 

 

 

 

$

(250

)

 

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2014 (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

 

$

23

 

 

Other current assets

 

$

(12

)

 

 

Other long-term assets, net

 

8

 

 

Other long-term assets, net

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

Interest rate derivatives

 

 

 

 

 

 

Other current liabilities

 

(44

)

 

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(26

)

Total derivatives designated as hedging instruments

 

 

 

$

31

 

 

 

 

$

(83

)

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Other current assets

 

$

439

 

 

Other current assets

 

$

(246

)

 

 

Other long-term assets, net

 

23

 

 

Other long-term assets, net

 

(3

)

 

 

 

 

 

 

 

Other current liabilities

 

(35

)

 

 

 

 

 

 

 

Other long-term liabilities and deferred credits

 

(5

)

 

 

 

 

 

 

 

 

 

 

 

Foreign currency derivatives

 

 

 

 

 

 

Other current liabilities

 

(12

)

Total derivatives not designated as hedging instruments

 

 

 

$

462

 

 

 

 

$

(301

)

 

 

 

 

 

 

 

 

 

 

 

Total derivatives

 

 

 

$

493

 

 

 

 

$

(384

)

 

18



Table of Contents

 

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 our 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, 2015, we had a net broker payable of $112 million (consisting of initial margin of $61 million reduced by $173 million of variation margin that had been returned to us). As of December 31, 2014, we had a net broker payable of $133 million (consisting of initial margin of $126 million reduced by $259 million of variation margin that had been returned to us).

 

The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements as of the dates indicated (in millions):

 

 

 

March 31, 2015

 

 

December 31, 2014

 

 

 

Derivative

 

Derivative

 

 

Derivative

 

Derivative

 

 

 

Asset Positions

 

Liability Positions

 

 

Asset Positions

 

Liability Positions

 

Netting Adjustments:

 

 

 

 

 

 

 

 

 

 

Gross position - asset/(liability)

 

$

246

 

$

(250

)

 

$

493

 

$

(384

)

Netting adjustment

 

(52

)

52

 

 

(262

)

262

 

Cash collateral paid/(received)

 

(112

)

 

 

(133

)

 

Net position - asset/(liability)

 

$

82

 

$

(198

)

 

$

98

 

$

(122

)

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Location After Netting Adjustments:

 

 

 

 

 

 

 

 

 

 

Other current assets

 

$

64

 

$

 

 

$

71

 

$

 

Other long-term assets, net

 

18

 

 

 

27

 

 

Other current liabilities

 

 

(108

)

 

 

(91

)

Other long-term liabilities and deferred credits

 

 

(90

)

 

 

(31

)

 

 

$

82

 

$

(198

)

 

$

98

 

$

(122

)

 

As of March 31, 2015, there was a net loss of $237 million deferred in AOCI including tax effects.  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, 2015, we expect to reclassify a net gain of $9 million to earnings in the next twelve months.  The remaining deferred loss of $246 million is expected to be reclassified to earnings through 2049. A portion of these amounts are based on market prices as of March 31, 2015; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

 

The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three months ended March 31, 2015 and 2014 was as follows (in millions):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2015

 

2014

 

Commodity derivatives, net

 

$

3

 

$

(12

)

Interest rate derivatives, net

 

(75

)

(20

)

Total

 

$

(72

)