Edgar Filing: PLAINS ALL AMERICAN PIPELINE LP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________________

FORM 10-Q

________________________________________________________________________________________________________________________________

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

For the quarterly period ended September 30, 2016

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. ý 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). ý 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 ý		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 ý No

As of November 1, 2016, there were 412,962,773 Common Units outstanding.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

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	Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of September 30, 2016 and December 31, 2015	3
Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2016 and 2015	4
Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2016 and 2015	5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the nine months ended September 30, 2016 and 2015	5
Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2016 and 2015	6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the nine months ended September 30, 2016 and 2015	7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation	8
2. Recent Accounting Pronouncements	10
3. Net Income Per Common Unit	10
4. Accounts Receivable, Net	12
5. Inventory, Linefill and Base Gas and Long-term Inventory	12
6. Goodwill	13
7. Debt	13
8. Partners’ Capital and Distributions	14
9. Derivatives and Risk Management Activities	16
10. Related Party Transactions	24
11. Equity-Indexed Compensation Plans	25
12. Commitments and Contingencies	25
13. Operating Segments	30
14. Acquisitions, Investments in Unconsolidated Entities, Dispositions and Impairments	32
15. Simplification Transactions	32

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	35
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
Item 4. CONTROLS AND PROCEDURES	58

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS	60
Item 1A. RISK FACTORS	60
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
Item 3. DEFAULTS UPON SENIOR SECURITIES	60
Item 4. MINE SAFETY DISCLOSURES	60
Item 5. OTHER INFORMATION	60
Item 6. EXHIBITS	60
SIGNATURES	61

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PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)



	September 30, 2016			December 31, 2015
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	31		$	27
Trade accounts receivable and other receivables, net	1,946			1,785
Inventory	1,258			916
Other current assets	538			241
Total current assets	3,773			2,969

PROPERTY AND EQUIPMENT	16,103			15,654
Accumulated depreciation	(2,292		)	(2,180		)
Property and equipment, net	13,811			13,474

OTHER ASSETS
Goodwill	2,353			2,405
Investments in unconsolidated entities	2,216			2,027
Linefill and base gas	899			898
Long-term inventory	146			129
Other long-term assets, net	309			386
Total assets	$	23,507		$	22,288

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	2,280		$	2,038
Short-term debt	1,384			999
Other current liabilities	413			370
Total current liabilities	4,077			3,407

LONG-TERM LIABILITIES
Senior notes, net of unamortized discounts and debt issuance costs	9,130			9,698
Other long-term debt	504			677
Other long-term liabilities and deferred credits	722			567
Total long-term liabilities	10,356			10,942

COMMITMENTS AND CONTINGENCIES (NOTE 12)

PARTNERS’ CAPITAL
Series A preferred unitholders (63,126,331 units outstanding)	1,508			—
Common unitholders (408,107,646 and 397,727,624 units outstanding, respectively)	7,240			7,580
General partner	268			301
Total partners’ capital excluding noncontrolling interests	9,016			7,881
Noncontrolling interests	58			58
Total partners’ capital	9,074			7,939
Total liabilities and partners’ capital	$	23,507		$	22,288

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(unaudited)						(unaudited)
REVENUES
Supply and Logistics segment revenues	$	4,876		$	5,247		$	13,344		$	17,225
Transportation segment revenues	159			172			482			538
Facilities segment revenues	135			132			405			393
Total revenues	5,170			5,551			14,231			18,156

COSTS AND EXPENSES
Purchases and related costs	4,429			4,701			12,000			15,591
Field operating costs	289			348			893			1,111
General and administrative expenses	70			60			210			217
Depreciation and amortization	33			107			351			319
Total costs and expenses	4,821			5,216			13,454			17,238

OPERATING INCOME	349			335			777			918

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	46			45			133			134
Interest expense (net of capitalized interest of $11, $14, $37 and $42, respectively)	(113		)	(109		)	(339		)	(320		)
Other income/(expense), net	17			(4		)	46			(7		)

INCOME BEFORE TAX	299			267			617			725
Current income tax expense	(4		)	(11		)	(45		)	(72		)
Deferred income tax benefit/(expense)	3			(6		)	30			6

NET INCOME	298			250			602			659
Net income attributable to noncontrolling interests	(1		)	(1		)	(3		)	(2		)
NET INCOME ATTRIBUTABLE TO PAA	$	297		$	249		$	599		$	657

BASIC NET INCOME PER COMMON UNIT (NOTE 3):
Net income allocated to common unitholders — Basic	$	162		$	98		$	110		$	211
Basic weighted average common units outstanding	401			398			399			393
Basic net income per common unit	$	0.40		$	0.25		$	0.27		$	0.54

Net income allocated to common unitholders — Diluted	$	162		$	98		$	110		$	211
Diluted weighted average common units outstanding	402			399			400			395
Diluted net income per common unit	$	0.40		$	0.24		$	0.27		$	0.53

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(unaudited)						(unaudited)
Net income	$	298		$	250		$	602		$	659
Other comprehensive loss	(45		)	(311		)	—			(518		)
Comprehensive income/(loss)	253			(61		)	602			141
Comprehensive income attributable to noncontrolling interests	(1		)	(1		)	(3		)	(2		)
Comprehensive income/(loss) attributable to PAA	$	252		$	(62	)	$	599		$	139

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 Instruments			Translation Adjustments			Total
				(unaudited)
Balance at December 31, 2015	$	(203	)	$	(878	)	$	(1,081	)

Reclassification adjustments	7			—			7
Deferred loss on cash flow hedges	(178		)	—			(178		)
Currency translation adjustments	—			171			171
Total period activity	(171		)	171			—
Balance at September 30, 2016	$	(374	)	$	(707	)	$	(1,081	)



	Derivative Instruments			Translation Adjustments			Total
				(unaudited)
Balance at December 31, 2014	$	(159	)	$	(308	)	$	(467	)

Reclassification adjustments	(21		)	—			(21		)
Deferred loss on cash flow hedges	(28		)	—			(28		)
Currency translation adjustments	—			(469		)	(469		)
Total period activity	(49		)	(469		)	(518		)
Balance at September 30, 2015	$	(208	)	$	(777	)	$	(985	)

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Nine Months Ended September 30,
	2016			2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	602		$	659
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	351			319
Equity-indexed compensation expense	40			27
Inventory valuation adjustments	3			25
Deferred income tax benefit	(30		)	(6		)
(Gain)/loss on foreign currency revaluation	1			(20		)
Settlement of terminated interest rate hedging instruments	(50		)	(48		)
Change in fair value of Preferred Distribution Rate Reset Option (Note 9)	(42		)	—
Equity earnings in unconsolidated entities	(133		)	(134		)
Distributions from unconsolidated entities	151			159
Other	13			(5		)
Changes in assets and liabilities, net of acquisitions	(264		)	246
Net cash provided by operating activities	642			1,222

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(282		)	(104		)
Investments in unconsolidated entities	(171		)	(213		)
Additions to property, equipment and other	(1,030		)	(1,617		)
Cash paid for purchases of linefill and base gas	(7		)	(131		)
Proceeds from sales of assets	638			4
Other investing activities	(2		)	(8		)
Net cash used in investing activities	(854		)	(2,069		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 7)	(617		)	151
Net borrowings under senior secured hedged inventory facility (Note 7)	424			—
Proceeds from the issuance of senior notes	—			998
Repayments of senior notes (Note 7)	(175		)	(549		)
Net proceeds from the sale of Series A preferred units (Note 8)	1,569			—
Net proceeds from the sale of common units (Note 8)	283			1,099
Contributions from general partner	39			23
Distributions paid to common unitholders (Note 8)	(835		)	(802		)
Distributions paid to general partner (Note 8)	(464		)	(436		)
Other financing activities	(12		)	(15		)
Net cash provided by financing activities	212			469

Effect of translation adjustment on cash	4			(3		)

Net increase/(decrease) in cash and cash equivalents	4			(381		)
Cash and cash equivalents, beginning of period	27			403
Cash and cash equivalents, end of period	$	31		$	22

Cash paid for:
Interest, net of amounts capitalized	$	313		$	287
Income taxes, net of amounts refunded	$	78		$	43

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)



	Limited Partners						General Partner			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	Series A Preferred Unitholders			Common Unitholders			General Partner			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	(unaudited)
Balance at December 31, 2015	$	—		$	7,580		$	301		$	7,881		$	58		$	7,939
Net income	—			209			390			599			3			602
Cash distributions to partners	—			(835		)	(464		)	(1,299		)	(3		)	(1,302		)
Sale of Series A preferred units	1,509			—			33			1,542			—			1,542
Sale of common units	—			283			6			289			—			289
Other	(1		)	3			2			4			—			4
Balance at September 30, 2016	$	1,508		$	7,240		$	268		$	9,016		$	58		$	9,074



	Limited Partners			General Partner			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	Common Unitholders			General Partner			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	(unaudited)
Balance at December 31, 2014	$	7,793		$	340		$	8,133		$	58		$	8,191
Net income	215			442			657			2			659
Cash distributions to partners	(802		)	(436		)	(1,238		)	(2		)	(1,240		)
Sale of common units	1,099			22			1,121			—			1,121
Other comprehensive loss	(507		)	(11		)	(518		)	—			(518		)
Other	1			2			3			—			3
Balance at September 30, 2015	$	7,799		$	359		$	8,158		$	58		$	8,216

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

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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 13 for further discussion of our operating segments.

Our 2% general partner interest is held by PAA GP LLC (“PAA GP”), 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, 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 September 30, 2016, owned an approximate 42% limited partner interest in AAP. PAA GP Holdings LLC (“GP Holdings”) is PAGP’s general partner.

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, AAP and GP LLC.

Simplification Agreement

On July 11, 2016, PAA, PAGP, AAP, PAA GP, GP LLC and GP Holdings entered into a Simplification Agreement pursuant to which, upon closing, in exchange for the issuance by PAA to AAP of approximately 245.5 million common units representing limited partner interests in PAA and the assumption by PAA of AAP’s outstanding debt, AAP will contribute the IDRs to PAA and PAA GP’s 2% economic general partner interest in PAA will be converted into a non-economic general partner interest in PAA. Following the closing of the transactions contemplated by the Simplification Agreement, which is expected to occur on November 15, 2016, both PAA and PAGP will continue to be publicly traded. See Note 15 for further discussion of this transaction.

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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

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 $2 million and $7 million reclassified from “Depreciation and amortization” to “Interest expense, net” in our accompanying Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015, respectively, 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 and nine months ended September 30, 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.

Income Allocation

Net income for partners’ capital presentation purposes is allocated in accordance with our partnership agreement. Our general partner and common unitholders are allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner (the holder of the IDRs pursuant to our partnership agreement) for distributions declared and paid following the close of each quarter and (ii) cash distributions to our preferred unitholders. In accordance with our partnership agreement, our preferred unitholders are not allocated income for paid-in-kind distributions.

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For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit including application of the two-class method for MLPs. See Note 3 for additional information.

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 nine months ended September 30, 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. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our consolidated balance sheet.

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 do not anticipate that our adoption will have a material impact on our financial position, results of operations or cash flows.

In June 2016, the FASB issued new guidance for the accounting for credit losses on certain financial instruments. This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

In August 2016, the FASB issued guidance relating to the classification and presentation of eight specific cash flow issues. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We plan to early adopt this guidance during the fourth quarter of 2016, and we do not currently expect that our adoption will impact our statement of 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 and nine months ended September 30, 2016 as the effect was antidilutive. See Note 8 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

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to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 15 to our Consolidated Financial Statements included in Part IV of our 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Basic Net Income per Common Unit
Net income attributable to PAA	$	297		$	249		$	599		$	657
Distributions to Series A preferred units ⁽¹⁾	(33		)	—			(88		)	—
Distributions to general partner ⁽¹⁾	(102		)	(154		)	(412		)	(454		)
Distributions to participating securities⁽¹⁾	(1		)	(1		)	(3		)	(4		)
Undistributed loss allocated to general partner⁽¹⁾	1			4			14			12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$	162		$	98		$	110		$	211

Basic weighted average common units outstanding	401			398			399			393

Basic net income per common unit	$	0.40		$	0.25		$	0.27		$	0.54

Diluted Net Income per Common Unit
Net income attributable to PAA	$	297		$	249		$	599		$	657
Distributions to Series A preferred units ⁽¹⁾	(33		)	—			(88		)	—
Distributions to general partner ⁽¹⁾	(102		)	(154		)	(412		)	(454		)
Distributions to participating securities⁽¹⁾	(1		)	(1		)	(3		)	(4		)
Undistributed loss allocated to general partner⁽¹⁾	1			4			14			12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$	162		$	98		$	110		$	211

Basic weighted average common units outstanding	401			398			399			393
Effect of dilutive securities: Weighted average LTIP units	1			1			1			2
Diluted weighted average common units outstanding	402			399			400			395

Diluted net income per common unit	$	0.40		$	0.24		$	0.27		$	0.53

___________________________________________

⁽¹⁾

We calculate net income allocated 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.

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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 September 30, 2016 and December 31, 2015, we had received $62 million and $88 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $103 million and $36 million as of September 30, 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 September 30, 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 $3 million and $4 million at September 30, 2016 and December 31, 2015, respectively. 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):



	September 30, 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	20,494	barrels	$	879	$	42.89	16,345	barrels	$	608	$	37.20
NGL	21,087	barrels	321		$	15.22	13,907	barrels	218		$	15.68
Natural gas	15,116	Mcf	32		$	2.12	22,080	Mcf	53		$	2.40
Other	N/A		26		N/A		N/A		37		N/A
Inventory subtotal			1,258						916

Linefill and base gas
Crude oil	12,215	barrels	712		$	58.29	12,298	barrels	713		$	57.98
NGL	1,490	barrels	46		$	30.87	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	3,428	barrels	124		$	36.17	3,417	barrels	106		$	31.02
NGL	1,418	barrels	22		$	15.51	1,652	barrels	23		$	13.92
Long-term inventory subtotal			146						129

Total			$	2,303					$	1,943

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⁽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.

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Note 6—Goodwill

Goodwill by segment and changes in goodwill is reflected in the following table (in millions):



	Transportation			Facilities			Supply and Logistics		Total
Balance at December 31, 2015	$	815		$	1,087		$	503	$	2,405
Foreign currency translation adjustments	12			5			2		19
Dispositions and reclassifications to assets held for sale	(15		)	(56		)	—		(71		)
Balance at September 30, 2016	$	812		$	1,036		$	505	$	2,353

We completed our annual goodwill impairment test as of June 30, 2016 and determined that there was no impairment of goodwill.

Note 7—Debt

Debt consisted of the following (in millions):



	September 30, 2016		December 31, 2015
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively⁽¹⁾	$	256	$	696
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.5% and 1.4%, respectively⁽¹⁾	725		300
Senior notes:
6.13% senior notes due January 2017	400		—
Other	3		3
Total short-term debt	1,384		999

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $70 and $77, respectively	9,130		9,698
Commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively ⁽²⁾	500		672
Other	4		5
Total long-term debt	9,634		10,375
Total debt ⁽³⁾	$	11,018	$	11,374

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⁽¹⁾	We classified these commercial paper notes and credit facility borrowings as short-term as of September 30, 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⁾	As of September 30, 2016 and December 31, 2015, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis under our credit facilities.

⁽³⁾

Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.6 billion and $9.8 billion as of September 30, 2016 and December 31, 2015, respectively. We estimated the aggregate fair value of these notes as of September 30, 2016 and December 31, 2015 to be approximately $9.7 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.

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Credit Facilities

In August 2016, we extended the maturity dates of our senior unsecured revolving credit facility, senior secured hedged inventory facility and 364-day credit facility to August 2021, August 2019 and August 2017, respectively.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the nine months ended September 30, 2016 and 2015 were approximately $41.4 billion and $37.1 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $41.6 billion and $36.9 billion for the nine months ended September 30, 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 September 30, 2016 and December 31, 2015, we had outstanding letters of credit of $47 million and $46 million, respectively.

Senior Notes Repayments

Our $175 million, 5.88% senior notes were repaid in August 2016. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes.

Note 8—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 Series A preferred units in connection with in-kind distributions	2,096,204	—
Sale of common units	—	9,922,733
Issuance of common units under LTIP	—	457,289
Outstanding at September 30, 2016	63,126,331	408,107,646



	Limited Partners
	Common Units
Outstanding at December 31, 2014	375,107,793
Sale of common units	22,133,904
Issuance of common units under LTIP	485,927
Outstanding at September 30, 2015	397,727,624

Equity Offerings

Series A Preferred Unit Offering. On January 28, 2016 (the "Issuance Date"), 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 receive

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cumulative quarterly distributions, subject to customary antidilution adjustments, equal to $0.525 per unit ($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.

The purchasers may convert their Series A preferred units into common 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 into common 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 9 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.

Continuous Offering Program. During the nine months ended September 30, 2016, we issued an aggregate of approximately 9.9 million common units under our continuous offering program, generating proceeds of $289 million, including our general partner's proportionate capital contribution of $6 million, net of $2 million of commissions paid to our sales agents.

Distributions

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



	Distributions						Distributions per common unit
Distribution Date	Common Unitholders		General Partner		Total		Distributions per common unit
November 14, 2016 ⁽¹⁾	$	227	$	101	$	328	$	0.55
August 12, 2016	$	278	$	155	$	433	$	0.70
May 13, 2016	$	278	$	155	$	433	$	0.70
February 12, 2016	$	278	$	155	$	433	$	0.70

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⁽¹⁾	Payable to unitholders of record at the close of business on October 31, 2016 for the period July 1, 2016 through September 30, 2016.

In-Kind Distributions. On May 13, 2016, we issued 858,439 additional Series A preferred units in lieu of a cash distribution of $23 million. Such distribution was issued to Series A preferred unitholders of record as of April 29, 2016 and was prorated for the period beginning on January 28, 2016, the issuance date of the Series A preferred units, through March 31, 2016. On August 12, 2016, we issued 1,237,765 additional Series A preferred units in lieu of a cash distribution of $33 million.

On November 14, 2016, we will issue 1,262,522 additional Series A preferred units in lieu of a cash distribution of $33 million. Since the November 14, 2016 Series A preferred unit distribution was declared as payment-in-kind, this distribution payable was accrued to partners’ capital as of September 30, 2016 and thus had no net impact on the Series A preferred unitholders’ capital account.

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Noncontrolling Interests in Subsidiaries

As of September 30, 2016, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

Note 9—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 September 30, 2016, net derivative positions related to these activities included:


•	A net long position of 4.4 million barrels associated with our crude oil purchases, which was unwound ratably during October 2016 to match monthly average pricing.


•	A net short time spread position of 3.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2017.


•	A crude oil grade spread position of 16.0 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials.


•	A net short position of 12.9 Bcf through July 2017 related to anticipated sales of natural gas inventory.


•	A net short position of 34.7 million barrels through December 2019 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 September 30, 2016, our PLA hedges included a long call option position of 1.1 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 September 30, 2016, we had a long natural gas position of 31.6 Bcf of which 27.7 Bcf hedges our natural gas processing needs through December 2017. The

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remaining 3.9 Bcf of our natural gas position hedges natural gas required for operational needs through December 2018. We also had a short propane position of 5.1 million barrels through December 2017, a short butane position of 1.6 million barrels through December 2017 and a short WTI position of 0.7 million barrels through December 2017. 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 September 30, 2016, AOCI includes deferred losses of $353 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges. The majority of 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 September 30, 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	4/13/2017	2.02	%	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

During June 2016, we made a cash payment of approximately $52 million in connection with the termination of eight forward starting interest rate swaps that had an aggregate notional amount of $200 million and an average fixed rate of 3.06%. In conjunction with this termination, a loss of approximately $50 million was deferred to AOCI, and a loss of approximately $2 million was immediately recognized in interest expense attributable to the determination that a previously forecasted interest payment is now considered probable of not occurring.

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards.

As of September 30, 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.

The following table summarizes our open forward exchange contracts as of September 30, 2016 (in millions):

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		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2016	$	222	$	291	$1.00 - $1.31
	2017	$	51	$	67	$1.00 - $1.31

Forward exchange contracts that exchange USD for CAD:
	2016	$	273	$	355	$1.00 - $1.30
	2017	$	126	$	164	$1.00 - $1.30

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 September 30, 2016, the fair value of this embedded derivative was a liability of approximately $18 million. We recognized gains of approximately $17 million and $42 million during the three and nine months ended September 30, 2016, respectively, due to changes in fair value during the periods. See Note 8 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option.

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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 September 30, 2016									Three Months Ended September 30, 2015
Location of Gain/(Loss)	Derivatives in Hedging Relationships⁽¹⁾			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		$	10		$	11		$	42		$	14		$	56

Transportation segment revenues	—			1			1			—			2			2

Field operating costs	—			(2		)	(2		)	—			(9		)	(9		)

Interest Rate Derivatives

Interest expense, net	(2		)	—			(2		)	(4		)	—			(4		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			(1		)	(1		)	—			(9		)	(9		)

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			17			17			—			—			—

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(1	)	$	25		$	24		$	38		$	(2	)	$	36

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	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
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	$	1		$	(118	)	$	(117	)	$	30		$	24		$	54

Transportation segment revenues	—			4			4			—			6			6

Field operating costs	—			(2		)	(2		)	—			(11		)	(11		)

Interest Rate Derivatives

Interest expense, net	(8		)	—			(8		)	(9		)	—			(9		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			4			4			—			(26		)	(26		)

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			42			42			—			—			—

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(7	)	$	(70	)	$	(77	)	$	21		$	(7	)	$	14

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⁽¹⁾

During the nine months ended September 30, 2016 we reclassified losses of approximately $2 million and $2 million to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the nine months ended September 30, 2015, we reclassified a loss of approximately $4 million from AOCI to Interest expense, net due to an anticipated hedged transaction being probable of not occurring.

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The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of September 30, 2016 (in millions):



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	1

Interest rate derivatives				Other current liabilities	$	(72	)
				Other long-term liabilities and deferred credits	(103		)
Total derivatives designated as hedging instruments		$	1		$	(175	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	77	Other current assets	$	(119	)
	Other long-term liabilities and deferred credits	3		Other current liabilities	(10		)
				Other long-term liabilities and deferred credits	(18		)

Foreign currency derivatives	Other current liabilities	1		Other current liabilities	(4		)

Preferred Distribution Rate Reset Option				Other long-term liabilities and deferred credits	(18		)