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EX-32.2 - EXHIBIT 32.2 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit322.htm
EX-32.1 - EXHIBIT 32.1 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit321.htm
EX-31.2 - EXHIBIT 31.2 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit312.htm
EX-31.1 - EXHIBIT 31.1 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit311.htm
EX-12.1 - EXHIBIT 12.1 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit121.htm
EX-10.5 - EXHIBIT 10.5 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit105.htm
EX-10.4 - EXHIBIT 10.4 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit104.htm
EX-10.3 - EXHIBIT 10.3 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit103.htm
EX-10.2 - EXHIBIT 10.2 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit102.htm
EX-10.1 - EXHIBIT 10.1 - PLAINS ALL AMERICAN PIPELINE LPpaaq12018exhibit101.htm

 
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
 
OR
 
o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File Number: 1-14569
________________________________________________________________

PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
76-0582150
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
333 Clay Street, Suite 1600, Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)

(713) 646-4100
(Registrant’s telephone number, including area code)
________________________________________________________________
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  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.
 
 



PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
 
Page
 
 
 
 
 
 
 
 


2


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.

3


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.


4


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.

5


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.

6


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
 
 
 
(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
 
 
 
 
(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.


7


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.
 

8


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. 


9


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.


10


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



11


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



12


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



13


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.


14


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


15


 
(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

 
 

 

16


(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.


17


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
 
 
 
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.
 

18


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.

19


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.
 

20


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.
 

21


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





22


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
)


23


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




24


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