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 March 31, 2018

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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer ý		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o

(Do not check if a smaller reporting company)		Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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 May 1, 2018, there were 725,582,739 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 March 31, 2018 and December 31, 2017	3
Condensed Consolidated Statements of Operations: For the three months ended March 31, 2018 and 2017	4
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2018 and 2017	5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the three months ended March 31, 2018 and 2017	5
Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2018 and 2017	6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three months ended March 31, 2018 and 2017	7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation	8
2. Recent Accounting Pronouncements	10
3. Revenues	11
4. Net Income Per Common Unit	15
5. Accounts Receivable, Net	16
6. Inventory, Linefill and Base Gas and Long-term Inventory	16
7. Divestitures	17
8. Debt	17
9. Partners’ Capital and Distributions	18
10. Derivatives and Risk Management Activities	19
11. Related Party Transactions	27
12. Commitments and Contingencies	28
13. Operating Segments	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	55
Item 4. CONTROLS AND PROCEDURES	56

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS	57
Item 1A. RISK FACTORS	57
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	57
Item 3. DEFAULTS UPON SENIOR SECURITIES	57
Item 4. MINE SAFETY DISCLOSURES	57
Item 5. OTHER INFORMATION	57
Item 6. EXHIBITS	58
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)



	March 31, 2018			December 31, 2017
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	23		$	37
Trade accounts receivable and other receivables, net	3,023			3,029
Inventory	620			713
Other current assets	296			221
Total current assets	3,962			4,000

PROPERTY AND EQUIPMENT	16,937			16,862
Accumulated depreciation	(2,823		)	(2,773		)
Property and equipment, net	14,114			14,089

OTHER ASSETS
Goodwill	2,543			2,566
Investments in unconsolidated entities	2,882			2,756
Linefill and base gas	870			872
Long-term inventory	159			164
Other long-term assets, net	893			904
Total assets	$	25,423		$	25,351

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	3,571		$	3,457
Short-term debt	774			737
Other current liabilities	256			337
Total current liabilities	4,601			4,531

LONG-TERM LIABILITIES
Senior notes, net of unamortized discounts and debt issuance costs	8,935			8,933
Other long-term debt	115			250
Other long-term liabilities and deferred credits	736			679
Total long-term liabilities	9,786			9,862

COMMITMENTS AND CONTINGENCIES (NOTE 12)

PARTNERS’ CAPITAL
Series A preferred unitholders (71,090,468 and 69,696,542 units outstanding, respectively)	1,505			1,505
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787			788
Common unitholders (725,206,904 and 725,189,138 units outstanding, respectively)	8,744			8,665
Total partners’ capital	11,036			10,958
Total liabilities and partners’ capital	$	25,423		$	25,351

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 March 31,
	2018			2017
	(unaudited)
REVENUES
Supply and Logistics segment revenues	$	8,111		$	6,395
Transportation segment revenues	146			138
Facilities segment revenues	141			134
Total revenues	8,398			6,667

COSTS AND EXPENSES
Purchases and related costs	7,519			5,593
Field operating costs	292			288
General and administrative expenses	79			74
Depreciation and amortization	127			121
Total costs and expenses	8,017			6,076

OPERATING INCOME	381			591

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	75			53
Interest expense (net of capitalized interest of $6 and $6, respectively)	(106		)	(129		)
Other expense, net	(1		)	(5		)

INCOME BEFORE TAX	349			510
Current income tax expense	(13		)	(10		)
Deferred income tax expense	(48		)	(56		)

NET INCOME	$	288		$	444

NET INCOME PER COMMON UNIT (NOTE 4):
Net income allocated to common unitholders — Basic	$	237		$	406
Basic weighted average common units outstanding	725			691
Basic net income per common unit	$	0.33		$	0.59

Net income allocated to common unitholders — Diluted	$	237		$	443
Diluted weighted average common units outstanding	727			758
Diluted net income per common unit	$	0.33		$	0.58

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 March 31,
	2018			2017
	(unaudited)
Net income	$	288		$	444
Other comprehensive income/(loss)	(65		)	36
Comprehensive income	$	223		$	480

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			Other		Total
	(unaudited)
Balance at December 31, 2017	$	(223	)	$	(548	)	$	1	$	(770	)

Reclassification adjustments	2			—			—		2
Deferred gain on cash flow hedges	31			—			—		31
Currency translation adjustments	—			(98		)	—		(98		)
Total period activity	33			(98		)	—		(65		)
Balance at March 31, 2018	$	(190	)	$	(646	)	$	1	$	(835	)



	Derivative Instruments			Translation Adjustments			Other		Total
	(unaudited)
Balance at December 31, 2016	$	(228	)	$	(782	)	$	1	$	(1,009	)

Reclassification adjustments	2			—			—		2
Deferred gain on cash flow hedges	7			—			—		7
Currency translation adjustments	—			27			—		27
Total period activity	9			27			—		36
Balance at March 31, 2017	$	(219	)	$	(755	)	$	1	$	(973	)

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)



	Three Months Ended March 31,
	2018			2017
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	288		$	444
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	127			121
Equity-indexed compensation expense	17			12
Deferred income tax expense	48			56
(Gain)/loss on foreign currency revaluation	8			(3		)
Equity earnings in unconsolidated entities	(75		)	(53		)
Distributions on earnings from unconsolidated entities	101			52
Other	11			10
Changes in assets and liabilities, net of acquisitions	(4		)	177
Net cash provided by operating activities	521			816

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	—			(1,254		)
Investments in unconsolidated entities	(40		)	(123		)
Additions to property, equipment and other	(266		)	(275		)
Proceeds from sales of assets	83			161
Other investing activities	2			—
Net cash used in investing activities	(221		)	(1,491		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 8)	(8		)	149
Net borrowings under senior unsecured revolving credit facility (Note 8)	350			—
Net repayments under senior secured hedged inventory facility (Note 8)	(498		)	(501		)
Repayments of senior notes	—			(400		)
Net proceeds from sales of common units	—			1,664
Distributions paid to common unitholders (Note 9)	(218		)	(371		)
Other financing activities	63			125
Net cash provided by/(used in) financing activities	(311		)	666

Effect of translation adjustment on cash	(3		)	—

Net decrease in cash and cash equivalents	(14		)	(9		)
Cash and cash equivalents, beginning of period	37			47
Cash and cash equivalents, end of period	$	23		$	38

Cash paid for:
Interest, net of amounts capitalized	$	76		$	92
Income taxes, net of amounts refunded	$	9		$	27

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									Total Partners’ Capital
	Preferred Unitholders						Common Unitholders
	Series A			Series B			Common Unitholders
	(unaudited)
Balance at December 31, 2017	$	1,505		$	788		$	8,665		$	10,958
Impact of adoption of ASU 2017-05 (Note 2)	—			—			113			113
Net income	37			12			239			288
Distributions (Note 9)	(37		)	(12		)	(218		)	(267		)
Other comprehensive loss	—			—			(65		)	(65		)
Other	—			(1		)	10			9
Balance at March 31, 2018	$	1,505		$	787		$	8,744		$	11,036



	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	Series A Preferred Unitholders			Common Unitholders			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	(unaudited)
Balance at December 31, 2016	$	1,508		$	7,251		$	8,759		$	57		$	8,816
Net income	—			444			444			—			444
Distributions	—			(371		)	(371		)	(1		)	(372		)
Sales of common units	—			1,664			1,664			—			1,664
Other comprehensive income	—			36			36			—			36
Other	(1		)	3			2			—			2
Balance at March 31, 2017	$	1,507		$	9,027		$	10,534		$	56		$	10,590

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 primarily for crude oil, natural gas liquids (“NGL”) and natural gas. 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: Supply and Logistics, Transportation and Facilities. See Note 13 for further discussion of our operating segments.

Our non-economic 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, as of March 31, 2018, AAP also owned a limited partner interest in us through its ownership of approximately 283.9 million of our common units (approximately 36% of our total outstanding common units and Series A preferred units combined). 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 and managing member of GP LLC, and, at March 31, 2018, owned an approximate 55% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.

As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP.

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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)
ASC	=	Accounting Standards Codification
ASU	=	Accounting Standards Update
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CODM	=	Chief Operating Decision Maker
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
EPA	=	United States Environmental Protection Agency
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
ISDA	=	International Swaps and Derivatives Association
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
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 2017 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. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. 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. The condensed consolidated balance sheet data as of December 31, 2017 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, 2018 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.

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Note 2—Recent Accounting Pronouncements

Except as discussed below and in our 2017 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2018 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

In February 2017, the FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The ASU clarifies what type of transactions involving nonfinancial assets are covered by the scope of the standard and provides guidance on how to account for those transactions, including partial sales of real estate. Within this guidance, all sales and partial sales of businesses, which may have previously been accounted for using the in-substance real estate guidance, should follow the consolidation guidance. This guidance is effective for interim and annual periods beginning after December 15, 2017, and must be adopted at the same time as Topic 606. We adopted this ASU on January 1, 2018, using the modified retrospective approach. The cumulative effect of our adoption resulted in increases in both the carrying value of investments in unconsolidated entities and retained earnings of $113 million related to the retained noncontrolling interest in those entities from partial sales of businesses accounted for under in-substance real estate guidance during 2016 and 2017.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force), requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 31, 2017. We adopted this ASU on January 1, 2018. Our adoption did not have an impact on our statement of cash flows.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, followed by a series of related accounting standard updates (collectively referred to as “Topic 606”) 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 control of those goods or services. We adopted Topic 606 on January 1, 2018, and applied the modified retrospective approach. See Note 3 for additional information.

Other Accounting Standards Updates

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), 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 (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019 and are assessing the use of optional practical expedients. 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.

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Note 3—Revenues

Revenue Recognition

On January 1, 2018, we adopted Topic 606 using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605, Revenue Recognition.

There was no material impact to opening retained earnings as of January 1, 2018 due to the adoption of Topic 606. There also was no material impact to revenues, or any other financial statement line items, for the three months ended March 31, 2018 as a result of applying Topic 606.

Under Topic 606, we disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Our business activities are conducted through three operating segments: Supply and Logistics, Transportation and Facilities. See Note 13 for further discussion of our operating segments.

Supply and Logistics Segment Revenues from Contracts with Customers. The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by segment and type of activity (in millions):



	Three Months Ended March 31, 2018
Supply and Logistics revenues from contracts with customers
Crude oil transactions	$	7,023
NGL and other transactions	1,151
Total Supply and Logistics revenues from contracts with customers	$	8,174

Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. The consideration received under these contracts is variable based on commodity prices. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges which are excluded from Supply and Logistics segment revenues in our Condensed Consolidated Statements of Operations. Revenues recognized by our Supply and Logistics segment primarily represent margin based activities.

Additionally, we may utilize derivatives in connection with the transactions described above. Derivative revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue. The change in the fair value of derivatives that are not designated or do not qualify for hedge accounting is recognized in revenues each period along with the ineffective portion of the change in fair value of derivatives that are designated as cash flow hedges. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred in AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings.

Transportation Segment Revenues from Contracts with Customers. The following table presents our Transportation segment revenues from contracts with customers disaggregated by segment and type of activity (in millions):



	Three Months Ended March 31, 2018
Transportation revenues from contracts with customers
Tariff activities:
Crude oil pipelines	$	389
NGL pipelines	27
Total tariff activities	416
Trucking	34
Total Transportation revenues from contracts with customers	$	450

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Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date.

Facilities Segment Revenues from Contracts with Customers. The following table presents our Facilities segment revenues from contracts with customers disaggregated by segment and type of activity (in millions):



	Three Months Ended March 31, 2018
Facilities revenues from contracts with customers
Crude oil, NGL and other terminalling and storage	$	166
NGL and natural gas processing and fractionation	100
Rail load / unload	16
Total Facilities revenues from contracts with customers	$	282

Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (iii) fees from NGL fractionation and isomerization services, (iv) fees from natural gas and condensate processing services, (v) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services (“natural gas storage related activities”) and (vi) loading and unloading fees at our rail terminals.

We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Natural gas storage related activities fees are recognized in the period the natural gas moves across our header system. We recognize rail loading and unloading fees when the volumes are delivered or received.

Reconciliation to Total Revenues of Reportable Segments. Topic 606 requires us to provide information about the relationship between the disaggregated revenues presented above and segment revenues. These disclosures only include information regarding revenues associated with consolidated entities, and revenues from entities accounted for by the equity method are not included in the disclosures. The following table presents the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statement of Operations (in millions):



Three Months Ended March 31, 2018	Transportation		Facilities		Supply and Logistics			Total
Revenues from contracts with customers	$	450	$	282	$	8,174		$	8,906
Other items in revenues	4		10		(62		)	(48		)
Total revenues of reportable segments	$	454	$	292	$	8,112		$	8,858
Intersegment revenues								(460		)
Total revenues								$	8,398

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Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. These contracts are within the scope of Topic 606. In addition, we have certain buy/sell agreements that require customers to deliver a minimum volume over an agreed upon period that are within the scope of ASC Topic 845, Nonmonetary Transactions, (“Topic 845”). Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

At March 31, 2018 and December 31, 2017, counterparty deficiencies associated with agreements (under Topic 606 and Topic 845) that include minimum volume commitments totaled $59 million and $57 million, respectively, of which $44 million and $37 million, respectively, was recorded as a contract liability, which we refer to as deferred revenue. The remaining balance of $15 million and $20 million at March 31, 2018 and December 31, 2017, respectively, was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.

Contract Balances. Our contract balances primarily consist of trade accounts receivable and liabilities. Our liabilities primarily consist of deferred revenues and advance cash payments. We invoice customers in the month following that in which products or services were provided and generally require payment within 30 days of the invoice date. See Note 5 for further discussion of trade accounts receivable and advance cash payments. Included in these deferred revenues are amounts recognized under minimum volume commitments, as discussed above.

The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheet (in millions):



	March 31, 2018			December 31, 2017
Trade accounts receivable arising from revenues from contracts with customers	$	2,783		$	2,584
Other trade accounts receivables and other receivables ⁽¹⁾	3,674			3,709
Impact due to contractual rights of offset with counterparties	(3,434		)	(3,264		)
Trade accounts receivable and other receivables, net	$	3,023		$	3,029


⁽¹⁾	The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.

Our contract liabilities primarily consist of amounts received under minimum volume commitments for which revenues are yet to be recognized and customer pre-payments and deposits. The following table presents the change in the contract liability balance during the three months ended March 31, 2018 (in millions):



	Minimum Volume Commitments			Customer Prepayments and Other			Total Deferred Revenues
Balance at December 31, 2017	$	8		$	86		$	94
Amounts recognized as revenue	(5		)	(70		)	(75		)
Additions	5			95			100
Other	—			(3		)	(3		)
Balance at March 31, 2018	$	8		$	108		$	116

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Remaining Performance Obligations. Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2018 (in millions):



	Remainder of 2018		2019		2020		2021		2022		2023 and Thereafter
Pipeline revenues supported by minimum volume commitments ⁽¹⁾	$	77	$	158	$	225	$	214	$	212	$	682
Long-term storage, terminalling and throughput agreements revenues	327		347		276		212		168		679
Total	$	404	$	505	$	501	$	426	$	380	$	1,361


⁽¹⁾	Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects.

The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 requirements for presentation:


•	Minimum volume commitments related to the assets of equity method investees — contracts include those related to the Eagle Ford, BridgeTex, STACK, Caddo, Saddlehorn, White Cliffs, Cheyenne and Diamond pipeline systems;


•	Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions;


•	Supply and Logistics contracts within the scope of Topic 845 — including buy/sell arrangements with future committed volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems;


•	All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below;


•	Transportation and Facilities contracts that are short-term, as discussed below;


•	Contracts within the scope of ASC Topic 840, Leases; and


•	Contracts within the scope of ASC Topic 815, Derivatives and Hedging.

We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations under Topic 606 due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above.

Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, which excludes the presentation of remaining performance obligations for short-term transportation, storage and processing services, supply and logistics arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.

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Note 4—Net Income Per Common Unit

We calculate basic and diluted net income per common unit by dividing net income (after deducting amounts allocated to the preferred unitholders 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.

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards (which include LTIP awards and AAP Management Units). When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2018 as the effect was antidilutive. Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards and AAP Management Units that were deemed to be dilutive during the three months ended March 31, 2018 and 2017 were 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 16 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for a complete discussion of our LTIP awards and the AAP Management Units.

The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data):



	Three Months Ended March 31,
	2018			2017
Basic Net Income per Common Unit
Net income	$	288		$	444
Distributions to Series A preferred unitholders	(37		)	(34		)
Distributions to Series B preferred unitholders	(12		)	—
Distributions to participating securities	(1		)	(1		)
Other	(1		)	(3		)
Net income allocated to common unitholders ⁽¹⁾	$	237		$	406

Basic weighted average common units outstanding	725			691

Basic net income per common unit	$	0.33		$	0.59

Diluted Net Income per Common Unit
Net income	$	288		$	444
Distributions to Series A preferred unitholders	(37		)	—
Distributions to Series B preferred unitholders	(12		)	—
Distributions to participating securities	(1		)	(1		)
Other	(1		)	—
Net income allocated to common unitholders ⁽¹⁾	$	237		$	443

Basic weighted average common units outstanding	725			691
Effect of dilutive securities:
Series A preferred units	—			65
Equity-indexed compensation plan awards	2			2
Diluted weighted average common units outstanding	727			758

Diluted net income per common unit	$	0.33		$	0.58

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⁽¹⁾

We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.

Note 5—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 and perform credit reviews of each customer 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, credit insurance or parental guarantees. As of March 31, 2018 and December 31, 2017, we had received $132 million and $117 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $44 million and $54 million as of March 31, 2018 and December 31, 2017, 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 the majority of our net-cash 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, 2018 and December 31, 2017, 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 at both March 31, 2018 and December 31, 2017. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Note 6—Inventory, Linefill and Base Gas and Long-term Inventory

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



	March 31, 2018						December 31, 2017
	Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾		Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾
Inventory
Crude oil	9,171	barrels	$	494	$	53.87	7,800	barrels	$	402	$	51.54
NGL	4,144	barrels	115		$	27.75	10,774	barrels	294		$	27.29
Other	N/A		11		N/A		N/A		17		N/A
Inventory subtotal			620						713

Linefill and base gas
Crude oil	12,428	barrels	719		$	57.85	12,340	barrels	719		$	58.27
NGL	1,596	barrels	43		$	26.94	1,597	barrels	45		$	28.18
Natural gas	24,976	Mcf	108		$	4.32	24,976	Mcf	108		$	4.32
Linefill and base gas subtotal			870						872

Long-term inventory
Crude oil	1,823	barrels	108		$	59.24	1,870	barrels	105		$	56.15
NGL	1,989	barrels	51		$	25.64	2,167	barrels	59		$	27.23
Long-term inventory subtotal			159						164

Total			$	1,649					$	1,749

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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.

Note 7—Divestitures

During the first quarter of 2018, we received proceeds from asset sales of $83 million, and we received an additional approximately $255 million from sales completed subsequent to quarter end through May 1, 2018. The assets sold primarily included non-core property and equipment previously reported in our Facilities and Transportation segments. As of March 31, 2018, we had classified approximately $150 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) related to these transactions.

Note 8—Debt

Debt consisted of the following (in millions):



	March 31, 2018		December 31, 2017
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 2.8% and 2.4%, respectively⁽¹⁾	$	116	$	—
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.9% and 2.6%, respectively⁽¹⁾	285		664
Senior unsecured revolving credit facility, bearing a weighted-average interest rate of 3.0% ⁽¹⁾	238		—
Other	135		73
Total short-term debt ⁽²⁾	774		737

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $65 and $67, respectively ⁽³⁾	8,935		8,933
Commercial paper notes and senior secured hedged inventory facility borrowings ⁽³⁾	—		247
Senior unsecured revolving credit facility ⁽³⁾	112		—
Other	3		3
Total long-term debt	9,050		9,183
Total debt ⁽⁴⁾	$	9,824	$	9,920


⁽¹⁾	We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2018 and December 31, 2017, 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 March 31, 2018 and December 31, 2017, balance includes borrowings of $217 million and $212 million, respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.


⁽³⁾	As of March 31, 2018 and December 31, 2017, we classified a portion of our commercial paper notes and credit facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis.

⁽⁴⁾

Our fixed-rate senior notes had a face value of approximately $9.0 billion at both March 31, 2018 and December 31, 2017. We estimated the aggregate fair value of these notes as of March 31, 2018 and December 31, 2017 to be approximately $8.8 billion and $9.1 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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Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the three months ended March 31, 2018 and 2017 were approximately $10.5 billion and $18.8 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $10.7 billion and $19.2 billion for the three months ended March 31, 2018 and 2017, 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 and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At March 31, 2018 and December 31, 2017, we had outstanding letters of credit of $102 million and $166 million, respectively.

Note 9—Partners’ Capital and Distributions

Units Outstanding

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



	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2017	69,696,542	800,000	725,189,138
Issuance of Series A preferred units in connection with in-kind distribution	1,393,926	—	—
Issuances of common units under LTIP	—	—	17,766
Outstanding at March 31, 2018	71,090,468	800,000	725,206,904



	Limited Partners
	Series A Preferred Units	Common Units
Outstanding at December 31, 2016	64,388,853	669,194,419
Issuance of Series A preferred units in connection with in-kind distribution	1,287,773	—
Sales of common units	—	54,119,893
Issuances of common units under LTIP	—	90,682
Outstanding at March 31, 2017	65,676,626	723,404,994

Distributions

Common Unit Distributions. The following table details distributions paid during or pertaining to the first three months of 2018 (in millions, except per unit data):



	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP		Total Cash Distribution
May 15, 2018 ⁽¹⁾	$	133	$	85	$	218	$	0.30
February 14, 2018	$	133	$	85	$	218	$	0.30


⁽¹⁾	Payable to unitholders of record at the close of business on May 1, 2018 for the period from January 1, 2018 through March 31, 2018.

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Series A Preferred Unit Distributions. With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we were able to elect to pay distributions on our Series A preferred units in additional preferred units, in cash or a combination of both. On February 14, 2018, we issued 1,393,926 Series A preferred units in lieu of a cash distribution of $37 million on our Series A preferred units outstanding as of January 31, 2018, the record date for such distribution.

The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to any quarter ending after the Initial Distribution Period, we must pay distributions on our Series A preferred units in cash. On May 15, 2018, we will pay a cash distribution of $37 million ($0.525 per unit) on our Series A preferred units outstanding as of May 1, 2018, the record date for such distribution, for the period from January 1, 2018 through March 31, 2018. At March 31, 2018, such amount was accrued to distributions payable (in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet).

The purchasers may convert their Series A preferred units into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter).

Series B Preferred Unit Distributions. On May 15, 2018, we will pay the semi-annual cash distribution of $24.5 million ($30.625 per unit) on our Series B preferred units to holders of record at the close of business on May 1, 2018, for the period from November 15, 2017 through May 14, 2018. As of March 31, 2018, we had accrued approximately $18 million of distributions payable to our Series B preferred unitholders (in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet).

Note 10—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions.

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories:

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of March 31, 2018, net derivative positions related to these activities included:


•	A net long position of 3.3 million barrels associated with our crude oil purchases, which was unwound ratably during April 2018 to match monthly average pricing.


•	A net short time spread position of 6.7 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through June 2019.

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•	A crude oil grade basis position of 36.4 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials.


•	A net short position of 14.9 million barrels through February 2020 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. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of March 31, 2018, our PLA hedges included a short position consisting of crude oil futures of 1.1 million barrels and a long call option position of 0.7 million barrels through December 2019.

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, 2018, we had a long natural gas position of 51.3 Bcf which hedges our natural gas processing and operational needs through December 2020. We also had a short propane position of 7.9 million barrels through December 2019, a short butane position of 2.4 million barrels through December 2019 and a short WTI position of 0.8 million barrels through December 2019. In addition, we had a long power position of 0.3 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2019.

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 the benchmark interest rate associated with 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. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2018 (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

16 forward starting swaps (30-year)

400

6/15/2018

2.86

Cash flow hedge

Anticipated interest payments

8 forward starting swaps (30-year)

200

6/14/2019

2.83

Cash flow hedge

Currency Exchange Rate Risk Hedging

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

As of March 31, 2018, our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

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The following table summarizes our open forward exchange contracts as of March 31, 2018 (in millions):



		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2018	$	161	$	208	$1.00 - $1.29

Forward exchange contracts that exchange USD for CAD:
	2018	$	382	$	491	$1.00 - $1.29
	2019	$	21	$	27	$1.00 - $1.28

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 expense, net” in our Condensed Consolidated Statement of Operations. At March 31, 2018 and December 31, 2017, the fair value of this embedded derivative was a liability of approximately $26 million and $22 million, respectively. We recognized losses of approximately $4 million during both the three months ended March 31, 2018 and 2017. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional information regarding our Series A preferred units and Preferred Distribution Rate Reset Option.

Summary of Financial Impact

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

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



	Three Months Ended March 31, 2018								Three Months Ended March 31, 2017
Location of Gain/(Loss)	Derivatives in Hedging Relationships		Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	—	$	(45	)	$	(45	)	$	—		$	96		$	96

Field operating costs	—		1			1			—			(3		)	(3		)

Interest Rate Derivatives

Interest expense, net	1		—			1			(2		)	—			(2		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—		(6		)	(6		)	—			2			2

Preferred Distribution Rate Reset Option

Other expense, net	—		(4		)	(4		)	—			(4		)	(4		)

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	1	$	(54	)	$	(53	)	$	(2	)	$	91		$	89

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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 March 31, 2018 (in millions):



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Interest rate derivatives	Other current assets	$	2	Other current liabilities	$	(15	)
	Other long-term assets, net	1		Other long-term liabilities and deferred credits	(1		)
	Other current liabilities	11
Total derivatives designated as hedging instruments		$	14		$	(16	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	260	Other current assets	$	(418	)
	Other long-term assets, net	9		Other long-term assets, net	(2		)
	Other current liabilities	9		Other current liabilities	(72		)
	Other long-term liabilities and deferred credits	1		Other long-term liabilities and deferred credits	(14		)

Foreign currency derivatives				Other current liabilities	(1		)


Preferred Distribution Rate Reset Option		—		Other long-term liabilities and deferred credits	(26		)
Total derivatives not designated as hedging instruments		$	279		$	(533	)

Total derivatives		$	293		$	(549	)

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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 December 31, 2017 (in millions):



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Interest rate derivatives	Other current liabilities	$	2	Other current liabilities	$	(27	)
				Other long-term liabilities and deferred credits	(11		)
Total derivatives designated as hedging instruments		$	2		$	(38	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	73	Other current assets	$	(227	)
	Other long-term assets, net	1		Other current liabilities	(131		)
	Other current liabilities	5		Other long-term liabilities and deferred credits	(5		)
	Other long-term liabilities and deferred credits	3

Foreign currency derivatives	Other current assets	6		Other current assets	(2		)

Preferred Distribution Rate Reset Option		—		Other long-term liabilities and deferred credits	(22		)
Total derivatives not designated as hedging instruments		$	88		$	(387	)

Total derivatives		$	90		$	(425	)

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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable:



	March 31, 2018		December 31, 2017
Initial margin	$	41	$	48
Variation margin posted	176		164
Net broker receivable	$	217	$	212

Table of Contents

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



	March 31, 2018						December 31, 2017
	Derivative Asset Positions			Derivative Liability Positions			Derivative Asset Positions			Derivative Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	293		$	(549	)	$	90		$	(425	)
Netting adjustment	(441		)	441			(239		)	239
Cash collateral paid	217			—			212			—
Net position - asset/(liability)	$	69		$	(108	)	$	63		$	(186	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	61		$	—		$	62		$	—
Other long-term assets, net	8			—			1			—
Other current liabilities	—			(68		)	—			(151		)
Other long-term liabilities and deferred credits	—			(40		)	—			(35		)
	$	69		$	(108	)	$	63		$	(186	)

As of March 31, 2018, there was a net loss of $190 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at March 31, 2018, we expect to reclassify a net loss of $8 million to earnings in the next twelve months. The remaining deferred loss of $182 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of March 31, 2018; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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



	Three Months Ended March 31,
	2018		2017
Interest rate derivatives, net	$	31	$	7

At March 31, 2018 and December 31, 2017, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

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



	Fair Value as of March 31, 2018												Fair Value as of December 31, 2017
Recurring Fair Value Measures ⁽¹⁾	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Commodity derivatives	$	(92	)	$	(135	)	$	—		$	(227	)	$	5	$	(278	)	$	(8	)	$	(281	)
Interest rate derivatives	—			(2		)	—			(2		)	—		(36		)	—			(36		)
Foreign currency derivatives	—			(1		)	—			(1		)	—		4			—			4
Preferred Distribution Rate Reset Option	—			—			(26		)	(26		)	—		—			(22		)	(22		)
Total net derivative asset/(liability)	$	(92	)	$	(138	)	$	(26	)	$	(256	)