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Name | Symbol | Market | Type |
---|---|---|---|
Plains All American Pipeline | NYSE:PAA | NYSE | Trust |
Price Change | % Change | Price | High Price | Low Price | Open Price | Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 8.76 | 0 | 01:00:00 |
|
Delaware
|
|
76-0582150
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
333 Clay Street, Suite 1600, Houston, Texas
|
|
77002
|
(Address of principal executive offices)
|
|
(Zip Code)
|
Large accelerated filer
ý
|
|
Accelerated filer
o
|
|
|
|
Non-accelerated filer
o
|
|
Smaller reporting company
o
|
|
|
|
|
|
Emerging growth company
o
|
Title of each class
|
Trading Symbol(s)
|
Name of each exchange on which registered
|
Common Units
|
PAA
|
New York Stock Exchange
|
|
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
|
(unaudited)
|
||||||
REVENUES
|
|
|
|
|
|
||
Supply and Logistics segment revenues
|
$
|
8,022
|
|
|
$
|
8,111
|
|
Transportation segment revenues
|
197
|
|
|
146
|
|
||
Facilities segment revenues
|
156
|
|
|
141
|
|
||
Total revenues
|
8,375
|
|
|
8,398
|
|
||
|
|
|
|
||||
COSTS AND EXPENSES
|
|
|
|
|
|
||
Purchases and related costs
|
7,119
|
|
|
7,519
|
|
||
Field operating costs
|
326
|
|
|
292
|
|
||
General and administrative expenses
|
76
|
|
|
79
|
|
||
Depreciation and amortization
|
136
|
|
|
127
|
|
||
(Gains)/losses on asset sales and asset impairments, net
|
4
|
|
|
—
|
|
||
Total costs and expenses
|
7,661
|
|
|
8,017
|
|
||
|
|
|
|
||||
OPERATING INCOME
|
714
|
|
|
381
|
|
||
|
|
|
|
||||
OTHER INCOME/(EXPENSE)
|
|
|
|
|
|
||
Equity earnings in unconsolidated entities
|
89
|
|
|
75
|
|
||
Gain on investment in unconsolidated entities (Note 7)
|
267
|
|
|
—
|
|
||
Interest expense (net of capitalized interest of $11 and $6, respectively)
|
(101
|
)
|
|
(106
|
)
|
||
Other income/(expense), net
|
25
|
|
|
(1
|
)
|
||
|
|
|
|
||||
INCOME BEFORE TAX
|
994
|
|
|
349
|
|
||
Current income tax expense
|
(30
|
)
|
|
(13
|
)
|
||
Deferred income tax benefit/(expense)
|
6
|
|
|
(48
|
)
|
||
|
|
|
|
||||
NET INCOME
|
$
|
970
|
|
|
$
|
288
|
|
|
|
|
|
||||
NET INCOME PER COMMON UNIT (NOTE 4):
|
|
|
|
|
|
||
Net income allocated to common unitholders — Basic
|
$
|
917
|
|
|
$
|
237
|
|
Basic weighted average common units outstanding
|
727
|
|
|
725
|
|
||
Basic net income per common unit
|
$
|
1.26
|
|
|
$
|
0.33
|
|
|
|
|
|
||||
Net income allocated to common unitholders — Diluted
|
$
|
957
|
|
|
$
|
237
|
|
Diluted weighted average common units outstanding
|
800
|
|
|
727
|
|
||
Diluted net income per common unit
|
$
|
1.20
|
|
|
$
|
0.33
|
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
|
(unaudited)
|
||||||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
Other comprehensive income/(loss)
|
58
|
|
|
(65
|
)
|
||
Comprehensive income
|
$
|
1,028
|
|
|
$
|
223
|
|
|
Derivative
Instruments |
|
Translation
Adjustments |
|
Other
|
|
Total
|
||||||||
|
(unaudited)
|
||||||||||||||
Balance at December 31, 2018
|
$
|
(177
|
)
|
|
$
|
(853
|
)
|
|
$
|
—
|
|
|
$
|
(1,030
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Unrealized loss on hedges
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
||||
Currency translation adjustments
|
—
|
|
|
78
|
|
|
—
|
|
|
78
|
|
||||
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
Total period activity
|
(21
|
)
|
|
78
|
|
|
1
|
|
|
58
|
|
||||
Balance at March 31, 2019
|
$
|
(198
|
)
|
|
$
|
(775
|
)
|
|
$
|
1
|
|
|
$
|
(972
|
)
|
|
Derivative
Instruments |
|
Translation
Adjustments |
|
Other
|
|
Total
|
||||||||
|
(unaudited)
|
||||||||||||||
Balance at December 31, 2017
|
$
|
(223
|
)
|
|
$
|
(548
|
)
|
|
$
|
1
|
|
|
$
|
(770
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Unrealized gain on hedges
|
31
|
|
|
—
|
|
|
—
|
|
|
31
|
|
||||
Currency translation adjustments
|
—
|
|
|
(98
|
)
|
|
—
|
|
|
(98
|
)
|
||||
Total period activity
|
33
|
|
|
(98
|
)
|
|
—
|
|
|
(65
|
)
|
||||
Balance at March 31, 2018
|
$
|
(190
|
)
|
|
$
|
(646
|
)
|
|
$
|
1
|
|
|
$
|
(835
|
)
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
|
(unaudited)
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
|
|
||
Depreciation and amortization
|
136
|
|
|
127
|
|
||
(Gains)/losses on asset sales and asset impairments, net
|
4
|
|
|
—
|
|
||
Equity-indexed compensation expense
|
17
|
|
|
17
|
|
||
Deferred income tax (benefit)/expense
|
(6
|
)
|
|
48
|
|
||
Loss on foreign currency revaluation
|
4
|
|
|
8
|
|
||
Change in fair value of Preferred Distribution Rate Reset Option (Note 10)
|
(23
|
)
|
|
4
|
|
||
Equity earnings in unconsolidated entities
|
(89
|
)
|
|
(75
|
)
|
||
Distributions on earnings from unconsolidated entities
|
98
|
|
|
101
|
|
||
Gain on investment in unconsolidated entities (Note 7)
|
(267
|
)
|
|
—
|
|
||
Other
|
7
|
|
|
7
|
|
||
Changes in assets and liabilities
|
182
|
|
|
(4
|
)
|
||
Net cash provided by operating activities
|
1,033
|
|
|
521
|
|
||
|
|
|
|
||||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
||
Investments in unconsolidated entities
|
(125
|
)
|
|
(40
|
)
|
||
Additions to property, equipment and other
|
(280
|
)
|
|
(266
|
)
|
||
Proceeds from sales of assets
|
—
|
|
|
83
|
|
||
Cash paid for purchases of linefill and base gas
|
(16
|
)
|
|
—
|
|
||
Other investing activities
|
(8
|
)
|
|
2
|
|
||
Net cash used in investing activities
|
(429
|
)
|
|
(221
|
)
|
||
|
|
|
|
||||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
||
Net repayments under commercial paper program (Note 8)
|
—
|
|
|
(8
|
)
|
||
Net borrowings under senior unsecured revolving credit facility (Note 8)
|
—
|
|
|
350
|
|
||
Net repayments under senior secured hedged inventory facility (Note 8)
|
—
|
|
|
(498
|
)
|
||
Distributions paid to Series A preferred unitholders (Note 9)
|
(37
|
)
|
|
—
|
|
||
Distributions paid to common unitholders (Note 9)
|
(218
|
)
|
|
(218
|
)
|
||
Other financing activities
|
57
|
|
|
63
|
|
||
Net cash used in financing activities
|
(198
|
)
|
|
(311
|
)
|
||
|
|
|
|
||||
Effect of translation adjustment
|
(3
|
)
|
|
(3
|
)
|
||
|
|
|
|
||||
Net increase/(decrease) in cash and cash equivalents and restricted cash
|
403
|
|
|
(14
|
)
|
||
Cash and cash equivalents and restricted cash, beginning of period
|
66
|
|
|
37
|
|
||
Cash and cash equivalents and restricted cash, end of period
|
$
|
469
|
|
|
$
|
23
|
|
|
|
|
|
||||
Cash paid for:
|
|
|
|
|
|
||
Interest, net of amounts capitalized
|
$
|
70
|
|
|
$
|
76
|
|
Income taxes, net of amounts refunded
|
$
|
65
|
|
|
$
|
9
|
|
|
Limited Partners
|
|
Total
Partners’
Capital
|
||||||||||||
|
Preferred Unitholders
|
|
Common
Unitholders
|
|
|||||||||||
|
Series A
|
|
Series B
|
|
|
||||||||||
|
(unaudited)
|
||||||||||||||
Balance at December 31, 2018
|
$
|
1,505
|
|
|
$
|
787
|
|
|
$
|
9,710
|
|
|
$
|
12,002
|
|
Net income
|
37
|
|
|
12
|
|
|
921
|
|
|
970
|
|
||||
Distributions (Note 9)
|
(37
|
)
|
|
(12
|
)
|
|
(218
|
)
|
|
(267
|
)
|
||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
58
|
|
|
58
|
|
||||
Equity-indexed compensation expense
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
||||
Other
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||
Balance at March 31, 2019
|
$
|
1,505
|
|
|
$
|
787
|
|
|
$
|
10,470
|
|
|
$
|
12,762
|
|
|
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
|
—
|
|
|
—
|
|
|
113
|
|
|
113
|
|
||||
Balance at January 1, 2018
|
1,505
|
|
|
788
|
|
|
8,778
|
|
|
11,071
|
|
||||
Net income
|
37
|
|
|
12
|
|
|
239
|
|
|
288
|
|
||||
Distributions
|
(37
|
)
|
|
(12
|
)
|
|
(218
|
)
|
|
(267
|
)
|
||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
(65
|
)
|
|
(65
|
)
|
||||
Equity-indexed compensation expense
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
||||
Other
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
||||
Balance at March 31, 2018
|
$
|
1,505
|
|
|
$
|
787
|
|
|
$
|
8,744
|
|
|
$
|
11,036
|
|
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
|
TWh
|
=
|
Terawatt hour
|
USD
|
=
|
United States dollar
|
WTI
|
=
|
West Texas Intermediate
|
|
March 31,
2019 |
||
Cash and cash equivalents
|
$
|
436
|
|
Restricted cash
|
33
|
|
|
Total cash and cash equivalents and restricted cash
|
$
|
469
|
|
•
|
ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes;
|
•
|
ASU 2018-09, Codification Improvements;
|
•
|
ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting; and
|
•
|
ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Supply and Logistics segment revenues from contracts with customers
|
|
|
|
||||
Crude oil transactions
|
$
|
6,936
|
|
|
$
|
7,023
|
|
NGL and other transactions
|
910
|
|
|
1,151
|
|
||
Total Supply and Logistics segment revenues from contracts with customers
|
$
|
7,846
|
|
|
$
|
8,174
|
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Transportation segment revenues from contracts with customers
|
|
|
|
||||
Tariff activities:
|
|
|
|
||||
Crude oil pipelines
|
$
|
478
|
|
|
$
|
389
|
|
NGL pipelines
|
27
|
|
|
27
|
|
||
Total tariff activities
|
505
|
|
|
416
|
|
||
Trucking
|
39
|
|
|
34
|
|
||
Total Transportation segment revenues from contracts with customers
|
$
|
544
|
|
|
$
|
450
|
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Facilities segment revenues from contracts with customers
|
|
|
|
||||
Crude oil, NGL and other terminalling and storage
|
$
|
176
|
|
|
$
|
166
|
|
NGL and natural gas processing and fractionation
|
87
|
|
|
100
|
|
||
Rail load / unload
|
20
|
|
|
16
|
|
||
Total Facilities segment revenues from contracts with customers
|
$
|
283
|
|
|
$
|
282
|
|
Three Months Ended March 31, 2019
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Total
|
||||||||
Revenues from contracts with customers
|
|
$
|
544
|
|
|
$
|
283
|
|
|
$
|
7,846
|
|
|
$
|
8,673
|
|
Other items in revenues
|
|
12
|
|
|
16
|
|
|
176
|
|
|
204
|
|
||||
Total revenues of reportable segments
|
|
$
|
556
|
|
|
$
|
299
|
|
|
$
|
8,022
|
|
|
$
|
8,877
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
(502
|
)
|
|||||||
Total revenues
|
|
|
|
|
|
|
|
$
|
8,375
|
|
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
|
|
|
|
Contract Liabilities
|
||
Balance at December 31, 2018
|
|
$
|
338
|
|
Amounts recognized as revenue
|
|
(224
|
)
|
|
Additions
|
|
65
|
|
|
Balance at March 31, 2019
|
|
$
|
179
|
|
|
Remainder of 2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024 and Thereafter
|
||||||||||||
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements
(1)
|
$
|
136
|
|
|
$
|
223
|
|
|
$
|
213
|
|
|
$
|
209
|
|
|
$
|
208
|
|
|
$
|
648
|
|
Long-term storage, terminalling and throughput agreement revenues
|
311
|
|
|
350
|
|
|
248
|
|
|
178
|
|
|
145
|
|
|
393
|
|
||||||
Total
|
$
|
447
|
|
|
$
|
573
|
|
|
$
|
461
|
|
|
$
|
387
|
|
|
$
|
353
|
|
|
$
|
1,041
|
|
|
(1)
|
Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.
|
•
|
Minimum volume commitments on certain of our joint venture pipeline systems;
|
•
|
Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions;
|
•
|
Supply and Logistics buy/sell arrangements — Contracts include agreements 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;
|
•
|
Transportation and Facilities contracts that are short-term;
|
•
|
Contracts within the scope of ASC Topic 842,
Leases
; and
|
•
|
Contracts within the scope of ASC Topic 815,
Derivatives and Hedging
.
|
|
March 31,
2019 |
|
December 31, 2018
|
||||
Trade accounts receivable arising from revenues from contracts with customers
|
$
|
2,693
|
|
|
$
|
2,277
|
|
Other trade accounts receivables and other receivables
(1)
|
3,838
|
|
|
2,732
|
|
||
Impact due to contractual rights of offset with counterparties
|
(3,530
|
)
|
|
(2,555
|
)
|
||
Trade accounts receivable and other receivables, net
|
$
|
3,001
|
|
|
$
|
2,454
|
|
|
(1)
|
The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Basic Net Income per Common Unit
|
|
|
|
|
|
||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
Distributions to Series A preferred unitholders
|
(37
|
)
|
|
(37
|
)
|
||
Distributions to Series B preferred unitholders
|
(12
|
)
|
|
(12
|
)
|
||
Distributions to participating securities
|
(1
|
)
|
|
(1
|
)
|
||
Other
|
(3
|
)
|
|
(1
|
)
|
||
Net income allocated to common unitholders
(1)
|
$
|
917
|
|
|
$
|
237
|
|
|
|
|
|
||||
Basic weighted average common units outstanding
|
727
|
|
|
725
|
|
||
|
|
|
|
||||
Basic net income per common unit
|
$
|
1.26
|
|
|
$
|
0.33
|
|
|
|
|
|
||||
Diluted Net Income per Common Unit
|
|
|
|
|
|
||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
Distributions to Series A preferred unitholders
|
—
|
|
|
(37
|
)
|
||
Distributions to Series B preferred unitholders
|
(12
|
)
|
|
(12
|
)
|
||
Distributions to participating securities
|
(1
|
)
|
|
(1
|
)
|
||
Other
|
—
|
|
|
(1
|
)
|
||
Net income allocated to common unitholders
(1)
|
$
|
957
|
|
|
$
|
237
|
|
|
|
|
|
||||
Basic weighted average common units outstanding
|
727
|
|
|
725
|
|
||
Effect of dilutive securities:
|
|
|
|
||||
Series A preferred units
|
71
|
|
|
—
|
|
||
Equity-indexed compensation plan awards
|
2
|
|
|
2
|
|
||
Diluted weighted average common units outstanding
|
800
|
|
|
727
|
|
||
|
|
|
|
||||
Diluted net income per common unit
|
$
|
1.20
|
|
|
$
|
0.33
|
|
|
(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.
|
|
March 31, 2019
|
|
|
December 31, 2018
|
||||||||||||||||||||||
|
Volumes
|
|
Unit of
Measure |
|
Carrying
Value |
|
Price/
Unit (1) |
|
|
Volumes
|
|
Unit of
Measure |
|
Carrying
Value |
|
Price/
Unit (1) |
||||||||||
Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil
|
8,949
|
|
|
barrels
|
|
$
|
439
|
|
|
$
|
49.06
|
|
|
|
9,657
|
|
|
barrels
|
|
$
|
367
|
|
|
$
|
38.00
|
|
NGL
|
2,366
|
|
|
barrels
|
|
45
|
|
|
$
|
19.02
|
|
|
|
10,384
|
|
|
barrels
|
|
262
|
|
|
$
|
25.23
|
|
||
Other
|
N/A
|
|
|
|
|
14
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
11
|
|
|
N/A
|
|
||||
Inventory subtotal
|
|
|
|
|
|
498
|
|
|
|
|
|
|
|
|
|
|
|
640
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Linefill and base gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil
|
13,169
|
|
|
barrels
|
|
751
|
|
|
$
|
57.03
|
|
|
|
13,312
|
|
|
barrels
|
|
761
|
|
|
$
|
57.17
|
|
||
NGL
|
1,720
|
|
|
barrels
|
|
48
|
|
|
$
|
27.91
|
|
|
|
1,730
|
|
|
barrels
|
|
47
|
|
|
$
|
27.17
|
|
||
Natural gas
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
|
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
||
Linefill and base gas subtotal
|
|
|
|
|
|
907
|
|
|
|
|
|
|
|
|
|
|
|
916
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil
|
2,315
|
|
|
barrels
|
|
129
|
|
|
$
|
55.72
|
|
|
|
1,890
|
|
|
barrels
|
|
79
|
|
|
$
|
41.80
|
|
||
NGL
|
2,363
|
|
|
barrels
|
|
52
|
|
|
$
|
22.01
|
|
|
|
2,368
|
|
|
barrels
|
|
57
|
|
|
$
|
24.07
|
|
||
Long-term inventory subtotal
|
|
|
|
|
|
181
|
|
|
|
|
|
|
|
|
|
|
|
136
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total
|
|
|
|
|
|
$
|
1,586
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,692
|
|
|
|
|
|
(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.
|
|
Transportation
|
|
Facilities
|
|
Supply and Logistics
|
|
Total
|
||||||||
Balance at December 31, 2018
|
$
|
1,040
|
|
|
$
|
978
|
|
|
$
|
503
|
|
|
$
|
2,521
|
|
Foreign currency translation adjustments
|
5
|
|
|
2
|
|
|
1
|
|
|
8
|
|
||||
Balance at March 31, 2019
|
$
|
1,045
|
|
|
$
|
980
|
|
|
$
|
504
|
|
|
$
|
2,529
|
|
Entity
(1)
|
|
Type of Operation
|
|
Ownership Interest at March 31, 2019
|
|
March 31, 2019
|
|
December 31, 2018
|
||||
Advantage Pipeline Holdings LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
$
|
72
|
|
|
$
|
72
|
|
BridgeTex Pipeline Company, LLC
|
|
Crude Oil Pipeline
|
|
20%
|
|
434
|
|
|
435
|
|
||
Cactus II Pipeline LLC
|
|
Crude Oil Pipeline
(2)
|
|
65%
|
|
531
|
|
|
455
|
|
||
Caddo Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
65
|
|
|
65
|
|
||
Capline Pipeline Company LLC
|
|
Crude Oil Pipeline
(3)
|
|
54%
|
|
455
|
|
|
—
|
|
||
Cheyenne Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
44
|
|
|
44
|
|
||
Diamond Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
484
|
|
|
479
|
|
||
Eagle Ford Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
396
|
|
|
383
|
|
||
Eagle Ford Terminals Corpus Christi LLC
|
|
Crude Oil Terminal and Dock
(2)
|
|
50%
|
|
117
|
|
|
108
|
|
||
Midway Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
77
|
|
|
78
|
|
||
Saddlehorn Pipeline Company, LLC
|
|
Crude Oil Pipeline
|
|
40%
|
|
215
|
|
|
215
|
|
||
Settoon Towing, LLC
|
|
Barge Transportation Services
|
|
50%
|
|
58
|
|
|
58
|
|
||
STACK Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
117
|
|
|
120
|
|
||
White Cliffs Pipeline, LLC
|
|
Crude Oil Pipeline
|
|
36%
|
|
191
|
|
|
190
|
|
||
Wink to Webster Pipeline LLC (“W2W Pipeline”)
|
|
Crude Oil Pipeline
(2)
|
|
20%
|
|
7
|
|
|
—
|
|
||
Total Investments in Unconsolidated Entities
|
|
|
|
|
|
$
|
3,263
|
|
|
$
|
2,702
|
|
|
(1)
|
Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment.
|
(2)
|
Asset is currently under construction by the entity and has not yet been placed in service.
|
(3)
|
The Capline pipeline was taken out of service in the fourth quarter of 2018. The members of Capline Pipeline Company LLC launched a binding open season to solicit shipper interest for a reversal of the Capline pipeline and the initiation of southbound service.
|
|
March 31,
2019 |
|
December 31,
2018 |
||||
SHORT-TERM DEBT
|
|
|
|
|
|
||
Other
|
$
|
149
|
|
|
$
|
66
|
|
Total short-term debt
|
149
|
|
|
66
|
|
||
|
|
|
|
||||
LONG-TERM DEBT
|
|
|
|
||||
Senior notes, net of unamortized discounts and debt issuance costs of $57 and $59, respectively
(1) (2)
|
8,943
|
|
|
8,941
|
|
||
GO Zone term loans, net of debt issuance costs of $2 and $2, respectively, bearing a weighted-average interest rate of 3.2% and 3.1%, respectively
(2)
|
198
|
|
|
198
|
|
||
Other
|
36
|
|
|
4
|
|
||
Total long-term debt
|
9,177
|
|
|
9,143
|
|
||
Total debt
|
$
|
9,326
|
|
|
$
|
9,209
|
|
|
(1)
|
As of
March 31, 2019
, we classified our
$500 million
,
5.75%
senior notes due January 2020 and our
$500 million
,
2.60%
senior notes due December 2019 as long-term, and as of
December 31, 2018
, we classified our
$500 million
,
2.60%
senior notes due December 2019 as long-term based on our ability and intent to refinance such amounts on a long-term basis.
|
(2)
|
Our fixed-rate senior notes had a face value of approximately
$9.0 billion
at both
March 31, 2019
and
December 31, 2018
. We estimated the aggregate fair value of these notes as of
March 31, 2019
and
December 31, 2018
to be approximately
$9.1 billion
and
$8.6 billion
, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes and GO Zone term loans are based upon observable market data and are classified in Level 2 of the fair value hierarchy.
|
|
Limited Partners
|
|||||||
|
Series A Preferred Units
|
|
Series B Preferred Units
|
|
Common Units
|
|||
Outstanding at December 31, 2018
|
71,090,468
|
|
|
800,000
|
|
|
726,361,924
|
|
Issuances of common units under equity-indexed compensation plans
|
—
|
|
|
—
|
|
|
423,889
|
|
Outstanding at March 31, 2019
|
71,090,468
|
|
|
800,000
|
|
|
726,785,813
|
|
|
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 equity-indexed compensation plans
|
—
|
|
|
—
|
|
|
17,766
|
|
Outstanding at March 31, 2018
|
71,090,468
|
|
|
800,000
|
|
|
725,206,904
|
|
|
|
Series A Preferred Unitholders
|
|||||||
Distribution Payment Date
|
|
Cash Distribution
|
|
|
Distribution per Unit
|
||||
May 15, 2019
(1)
|
|
$
|
37
|
|
|
|
$
|
0.525
|
|
February 14, 2019
|
|
$
|
37
|
|
|
|
$
|
0.525
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
May 1, 2019
for the period from
January 1, 2019
through
March 31, 2019
. At
March 31, 2019
, such amount was accrued to distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.
|
|
|
Series B Preferred Unitholders
|
|||||||
Distribution Payment Date
|
|
Cash Distribution
|
|
|
Distribution per Unit
|
||||
May 15, 2019
(1)
|
|
$
|
24.5
|
|
|
|
$
|
30.625
|
|
|
(1)
|
Payable to unitholders of record at the close of business on May 1, 2019 for the period from November 15, 2018 through May 14, 2019.
|
|
|
Distributions
|
|
|
Cash Distribution per Common Unit
|
||||||||||||
|
|
Common Unitholders
|
|
Total Cash Distribution
|
|
|
|||||||||||
Distribution Payment Date
|
|
Public
|
|
AAP
|
|
|
|
||||||||||
May 15, 2019
(1)
|
|
$
|
161
|
|
|
$
|
101
|
|
|
$
|
262
|
|
|
|
$
|
0.36
|
|
February 14, 2019
|
|
$
|
134
|
|
|
$
|
84
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
May 1, 2019
for the period from
January 1, 2019
through
March 31, 2019
.
|
•
|
A net long position of
3.8 million
barrels associated with our crude oil purchases, which was unwound ratably during
April 2019
to match monthly average pricing.
|
•
|
A net short time spread position of
2.8 million
barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through
June 2020
.
|
•
|
A crude oil basis spread position of
42.8 million
barrels through
December 2020
. These derivatives allow us to lock in grade basis differentials.
|
•
|
A net short position of
5.2 million
barrels through
March 2021
related to anticipated net sales of crude oil and NGL inventory.
|
|
|
Notional Volume
|
|
|
|
|
(Short)/Long
|
|
Remaining Tenor
|
Natural gas purchases
|
|
54.8 Bcf
|
|
December 2022
|
Propane sales
|
|
(6.2) MMbls
|
|
December 2020
|
Butane sales
|
|
(2.3) MMbls
|
|
December 2020
|
Condensate sales (WTI position)
|
|
(0.6) MMbls
|
|
December 2020
|
Specification products sales (put options)
|
|
0.7 MMbls
|
|
September 2019
|
Power supply requirements
(1)
|
|
1.2 TWh
|
|
December 2022
|
|
(1)
|
Power position to hedge a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants.
|
Hedged Transaction
|
|
Number and Types of
Derivatives Employed |
|
Notional
Amount |
|
Expected
Termination Date |
|
Average Rate
Locked |
|
Accounting
Treatment |
|||
Anticipated interest payments
|
|
8 forward starting swaps (30-year)
|
|
$
|
200
|
|
|
6/14/2019
|
|
2.83
|
%
|
|
Cash flow hedge
|
Anticipated interest payments
|
|
8 forward starting swaps
(30-year)
|
|
$
|
200
|
|
|
6/15/2020
|
|
3.06
|
%
|
|
Cash flow hedge
|
|
|
|
|
USD
|
|
CAD
|
|
Average Exchange Rate
USD to CAD |
||||
Forward exchange contracts that exchange CAD for USD:
|
|
|
|
|
|
|
|
|
|
|
||
|
|
2019
|
|
$
|
4
|
|
|
$
|
5
|
|
|
$1.00 - $1.34
|
|
|
|
|
|
|
|
|
|
||||
Forward exchange contracts that exchange USD for CAD:
|
|
|
|
|
|
|
|
|
|
|
||
|
|
2019
|
|
$
|
144
|
|
|
$
|
191
|
|
|
$1.00 - $1.33
|
|
Three Months Ended March 31, 2019
|
||||||||||||||||||
Location of Gain/(Loss)
|
Commodity
Derivatives |
|
Foreign Currency Derivatives
|
|
Preferred Distribution Rate Reset Option
|
|
Interest Rate Derivatives
|
|
Total
|
||||||||||
Supply and Logistics segment revenues
(1)
|
$
|
213
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
218
|
|
Field operating costs
(1)
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|||||
Interest expense, net
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|||||
Other income/(expense), net
(1)
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
23
|
|
|||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
$
|
220
|
|
|
$
|
5
|
|
|
$
|
23
|
|
|
$
|
(2
|
)
|
|
$
|
246
|
|
|
Three Months Ended March 31, 2018
|
||||||||||||||||||
Location of Gain/(Loss)
|
Commodity
Derivatives |
|
Foreign Currency Derivatives
|
|
Preferred Distribution Rate Reset Option
|
|
Interest Rate Derivatives
|
|
Total
|
||||||||||
Supply and Logistics segment revenues
(1)
|
$
|
(45
|
)
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(51
|
)
|
Field operating costs
(1)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Interest expense, net
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|||||
Other income/(expense), net
(1)
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
$
|
(44
|
)
|
|
$
|
(6
|
)
|
|
$
|
(4
|
)
|
|
$
|
1
|
|
|
$
|
(53
|
)
|
|
(1)
|
Derivatives not designated as a hedge.
|
(2)
|
Derivatives in hedging relationships.
|
|
|
Derivatives Not Designated As Hedging Instruments
|
|
|
|
|
||||||||||||||||||
Balance Sheet Location
|
|
Commodity
Derivatives |
|
Foreign Currency Derivatives
|
|
Preferred Distribution Rate Reset Option
|
|
Total
|
|
Interest Rate Derivatives
(1)
|
|
Total Derivatives
|
||||||||||||
Derivative Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other current assets
|
|
$
|
450
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
450
|
|
|
$
|
—
|
|
|
$
|
450
|
|
Other long-term assets, net
|
|
31
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|
—
|
|
|
31
|
|
||||||
Other current liabilities
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||
Other long-term liabilities and deferred credits
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
||||||
Total Derivative Assets
|
|
$
|
485
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
485
|
|
|
$
|
—
|
|
|
$
|
485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other current assets
|
|
$
|
(121
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(121
|
)
|
|
$
|
—
|
|
|
$
|
(121
|
)
|
Other long-term assets, net
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
||||||
Other current liabilities
|
|
(3
|
)
|
|
(1
|
)
|
|
—
|
|
|
(4
|
)
|
|
(11
|
)
|
|
(15
|
)
|
||||||
Other long-term liabilities and deferred credits
|
|
(5
|
)
|
|
—
|
|
|
(13
|
)
|
|
(18
|
)
|
|
(19
|
)
|
|
(37
|
)
|
||||||
Total Derivative Liabilities
|
|
$
|
(132
|
)
|
|
$
|
(1
|
)
|
|
$
|
(13
|
)
|
|
$
|
(146
|
)
|
|
$
|
(30
|
)
|
|
$
|
(176
|
)
|
|
(1)
|
Derivatives in hedging relationships.
|
|
|
Derivatives Not Designated As Hedging Instruments
|
|
|
|
|
||||||||||||||||||
Balance Sheet Location
|
|
Commodity
Derivatives |
|
Foreign Currency Derivatives
|
|
Preferred Distribution Rate Reset Option
|
|
Total
|
|
Interest Rate Derivatives
(1)
|
|
Total Derivatives
|
||||||||||||
Derivative Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other current assets
|
|
$
|
441
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
441
|
|
|
$
|
2
|
|
|
$
|
443
|
|
Other long-term assets, net
|
|
34
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
34
|
|
||||||
Other long-term liabilities and deferred credits
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
||||||
Total Derivative Assets
|
|
$
|
478
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
478
|
|
|
$
|
2
|
|
|
$
|
480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivative Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other current assets
|
|
$
|
(182
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(182
|
)
|
|
$
|
—
|
|
|
$
|
(182
|
)
|
Other long-term assets, net
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
||||||
Other current liabilities
|
|
(10
|
)
|
|
(9
|
)
|
|
—
|
|
|
(19
|
)
|
|
(1
|
)
|
|
(20
|
)
|
||||||
Other long-term liabilities and deferred credits
|
|
(9
|
)
|
|
—
|
|
|
(36
|
)
|
|
(45
|
)
|
|
(8
|
)
|
|
(53
|
)
|
||||||
Total Derivative Liabilities
|
|
$
|
(208
|
)
|
|
$
|
(9
|
)
|
|
$
|
(36
|
)
|
|
$
|
(253
|
)
|
|
$
|
(9
|
)
|
|
$
|
(262
|
)
|
|
(1)
|
Derivatives in hedging relationships.
|
|
March 31,
2019 |
|
December 31,
2018 |
||||
Initial margin
|
$
|
76
|
|
|
$
|
95
|
|
Variation margin returned
|
(137
|
)
|
|
(91
|
)
|
||
Letters of credit
|
(69
|
)
|
|
(84
|
)
|
||
Net broker payable
|
$
|
(130
|
)
|
|
$
|
(80
|
)
|
|
March 31, 2019
|
|
|
December 31, 2018
|
||||||||||||
|
Derivative
Asset Positions |
|
Derivative
Liability Positions |
|
|
Derivative
Asset Positions |
|
Derivative
Liability Positions |
||||||||
Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Gross position - asset/(liability)
|
$
|
485
|
|
|
$
|
(176
|
)
|
|
|
$
|
480
|
|
|
$
|
(262
|
)
|
Netting adjustment
|
(128
|
)
|
|
128
|
|
|
|
(192
|
)
|
|
192
|
|
||||
Cash collateral received
|
(130
|
)
|
|
—
|
|
|
|
(80
|
)
|
|
—
|
|
||||
Net position - asset/(liability)
|
$
|
227
|
|
|
$
|
(48
|
)
|
|
|
$
|
208
|
|
|
$
|
(70
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Balance Sheet Location After Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets
|
$
|
199
|
|
|
$
|
—
|
|
|
|
$
|
181
|
|
|
$
|
—
|
|
Other long-term assets, net
|
28
|
|
|
—
|
|
|
|
27
|
|
|
—
|
|
||||
Other current liabilities
|
—
|
|
|
(14
|
)
|
|
|
—
|
|
|
(20
|
)
|
||||
Other long-term liabilities and deferred credits
|
—
|
|
|
(34
|
)
|
|
|
—
|
|
|
(50
|
)
|
||||
|
$
|
227
|
|
|
$
|
(48
|
)
|
|
|
$
|
208
|
|
|
$
|
(70
|
)
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Interest rate derivatives, net
|
$
|
(23
|
)
|
|
$
|
31
|
|
|
|
Fair Value as of March 31, 2019
|
|
|
Fair Value as of December 31, 2018
|
||||||||||||||||||||||||||||
Recurring Fair Value Measures
(1)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
Commodity derivatives
|
|
$
|
306
|
|
|
$
|
44
|
|
|
$
|
3
|
|
|
$
|
353
|
|
|
|
$
|
171
|
|
|
$
|
87
|
|
|
$
|
12
|
|
|
$
|
270
|
|
Interest rate derivatives
|
|
—
|
|
|
(30
|
)
|
|
—
|
|
|
(30
|
)
|
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
||||||||
Foreign currency derivatives
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
(9
|
)
|
||||||||
Preferred Distribution Rate Reset Option
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
(13
|
)
|
|
|
—
|
|
|
—
|
|
|
(36
|
)
|
|
(36
|
)
|
||||||||
Total net derivative asset/(liability)
|
|
$
|
306
|
|
|
$
|
13
|
|
|
$
|
(10
|
)
|
|
$
|
309
|
|
|
|
$
|
171
|
|
|
$
|
71
|
|
|
$
|
(24
|
)
|
|
$
|
218
|
|
|
(1)
|
Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Beginning Balance
|
$
|
(24
|
)
|
|
$
|
(30
|
)
|
Net gains/(losses) for the period included in earnings
|
23
|
|
|
(1
|
)
|
||
Settlements
|
(10
|
)
|
|
5
|
|
||
Derivatives entered into during the period
|
1
|
|
|
—
|
|
||
Ending Balance
|
$
|
(10
|
)
|
|
$
|
(26
|
)
|
|
|
|
|
||||
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period
|
$
|
24
|
|
|
$
|
(1
|
)
|
Lease Cost
|
|
Three Months Ended
March 31, 2019 |
||
Operating lease cost
|
|
$
|
32
|
|
Short-term lease cost
|
|
8
|
|
|
Other
(1)
|
|
1
|
|
|
Total lease cost
|
|
$
|
41
|
|
|
(1)
|
Includes immaterial finance lease costs, variable lease costs and sublease income.
|
|
Three Months Ended
March 31, 2019 |
||
Cash paid for amounts included in the measurement of lease liabilities:
|
|
||
Operating cash flows for operating leases
|
$
|
33
|
|
Financing cash flows for finance leases
|
$
|
4
|
|
Leases
|
|
Balance Sheet Location
|
|
March 31, 2019
|
||
Assets
|
|
|
|
|
||
Operating lease right-of-use assets
|
|
Long-term operating lease right-of-use assets, net
|
|
$
|
477
|
|
|
|
|
|
|
||
Finance lease right-of-use assets
|
|
Property and equipment
|
|
$
|
109
|
|
|
|
Accumulated depreciation
|
|
(17
|
)
|
|
|
|
Property and equipment, net
|
|
$
|
92
|
|
|
|
|
|
|
||
Total lease right-of-use assets
|
|
|
|
$
|
569
|
|
|
|
|
|
|
||
Liabilities
|
|
|
|
|
||
Operating lease liabilities
|
|
|
|
|
||
Current
|
|
Other current liabilities
|
|
$
|
104
|
|
Noncurrent
|
|
Long-term operating lease liability
|
|
383
|
|
|
Total operating lease liabilities
|
|
|
|
$
|
487
|
|
|
|
|
|
|
||
Finance lease liabilities
|
|
|
|
|
||
Current
|
|
Short-term debt
|
|
$
|
19
|
|
Noncurrent
|
|
Other long-term debt, net
|
|
36
|
|
|
Total finance lease liabilities
|
|
|
|
$
|
55
|
|
|
|
|
|
|
||
Total lease liabilities
|
|
|
|
$
|
542
|
|
|
Operating
|
|
Finance
|
||||
Future minimum lease payments
(1)
:
|
|
|
|
||||
Remainder of 2019
|
$
|
92
|
|
|
$
|
15
|
|
2020
|
108
|
|
|
16
|
|
||
2021
|
89
|
|
|
7
|
|
||
2022
|
75
|
|
|
7
|
|
||
2023
|
52
|
|
|
5
|
|
||
Thereafter
|
244
|
|
|
7
|
|
||
Total
|
660
|
|
|
57
|
|
||
Less: Present value discount
|
(173
|
)
|
|
(2
|
)
|
||
Lease liabilities
|
$
|
487
|
|
|
$
|
55
|
|
|
(1)
|
Excludes future minimum payments for short-term and other immaterial leases not included on our Condensed Consolidated Balance Sheet.
|
|
|
Remainder
of 2019 |
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||
Facilities segment lease revenue
|
|
$
|
11
|
|
|
$
|
15
|
|
|
$
|
16
|
|
|
$
|
17
|
|
|
$
|
13
|
|
|
$
|
159
|
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Revenues from related parties
(1) (2)
|
$
|
225
|
|
|
$
|
281
|
|
|
|
|
|
||||
Purchases and related costs from related parties
(2)
|
$
|
114
|
|
|
$
|
92
|
|
|
(1)
|
A majority of these revenues are included in “Supply and Logistics segment revenues” on our Condensed Consolidated Statements of Operations.
|
(2)
|
Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations.
|
|
March 31,
2019 |
|
December 31,
2018 |
||||
Trade accounts receivable and other receivables, net from related parties
(1) (2)
|
$
|
233
|
|
|
$
|
144
|
|
|
|
|
|
||||
Trade accounts payable to related parties
(1) (2) (3)
|
$
|
120
|
|
|
$
|
121
|
|
|
(1)
|
We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts.
|
(2)
|
Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager.
|
(3)
|
We have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a
50%
interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.
|
Three Months Ended March 31, 2019
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Intersegment Adjustment
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
External customers
(1)
|
|
$
|
303
|
|
|
$
|
156
|
|
|
$
|
8,022
|
|
|
$
|
(106
|
)
|
|
$
|
8,375
|
|
Intersegment
(2)
|
|
253
|
|
|
143
|
|
|
—
|
|
|
106
|
|
|
502
|
|
|||||
Total revenues of reportable segments
|
|
$
|
556
|
|
|
$
|
299
|
|
|
$
|
8,022
|
|
|
$
|
—
|
|
|
$
|
8,877
|
|
Equity earnings in unconsolidated entities
|
|
$
|
89
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
89
|
|
||
Segment Adjusted EBITDA
|
|
$
|
399
|
|
|
$
|
184
|
|
|
$
|
278
|
|
|
|
|
$
|
861
|
|
||
Maintenance capital
|
|
$
|
27
|
|
|
$
|
17
|
|
|
$
|
2
|
|
|
|
|
$
|
46
|
|
Three Months Ended March 31, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Intersegment Adjustment
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
External customers
(1)
|
|
$
|
253
|
|
|
$
|
141
|
|
|
$
|
8,111
|
|
|
$
|
(107
|
)
|
|
$
|
8,398
|
|
Intersegment
(2)
|
|
201
|
|
|
151
|
|
|
1
|
|
|
107
|
|
|
460
|
|
|||||
Total revenues of reportable segments
|
|
$
|
454
|
|
|
$
|
292
|
|
|
$
|
8,112
|
|
|
$
|
—
|
|
|
$
|
8,858
|
|
Equity earnings in unconsolidated entities
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
75
|
|
||
Segment Adjusted EBITDA
|
|
$
|
335
|
|
|
$
|
185
|
|
|
$
|
72
|
|
|
|
|
$
|
592
|
|
||
Maintenance capital
|
|
$
|
29
|
|
|
$
|
14
|
|
|
$
|
2
|
|
|
|
|
$
|
45
|
|
|
(1)
|
Transportation revenues from External customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See
Note 3
to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.
|
(2)
|
Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Segment Adjusted EBITDA
|
$
|
861
|
|
|
$
|
592
|
|
Adjustments
(1)
:
|
|
|
|
||||
Depreciation and amortization of unconsolidated entities
(2)
|
(12
|
)
|
|
(14
|
)
|
||
Gains from derivative activities net of inventory valuation adjustments
(3)
|
74
|
|
|
23
|
|
||
Long-term inventory costing adjustments
(4)
|
21
|
|
|
13
|
|
||
Deficiencies under minimum volume commitments, net
(5)
|
7
|
|
|
(10
|
)
|
||
Equity-indexed compensation expense
(6)
|
(3
|
)
|
|
(11
|
)
|
||
Net loss on foreign currency revaluation
(7)
|
(5
|
)
|
|
(10
|
)
|
||
Depreciation and amortization
|
(136
|
)
|
|
(127
|
)
|
||
Gains/(losses) on asset sales and asset impairments, net
|
(4
|
)
|
|
—
|
|
||
Gain on investment in unconsolidated entities
|
267
|
|
|
—
|
|
||
Interest expense, net
|
(101
|
)
|
|
(106
|
)
|
||
Other income/(expense), net
|
25
|
|
|
(1
|
)
|
||
Income before tax
|
994
|
|
|
349
|
|
||
Income tax expense
|
(24
|
)
|
|
(61
|
)
|
||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
|
(1)
|
Represents adjustments utilized by our CODM in the evaluation of segment results.
|
(2)
|
Includes our proportionate share of the depreciation and amortization and gains and losses on significant asset sales of equity method investments.
|
(3)
|
We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Segment Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.
|
(4)
|
We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from Segment Adjusted EBITDA.
|
(5)
|
We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. 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 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. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
|
(6)
|
Includes equity-indexed compensation expense associated with awards that will or may be settled in units.
|
(7)
|
Includes gains and losses realized on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency.
|
Item 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Executive Summary
|
•
|
Capital Projects
|
•
|
Results of Operations
|
•
|
Liquidity and Capital Resources
|
•
|
Off-Balance Sheet Arrangements
|
•
|
Recent Accounting Pronouncements
|
•
|
Critical Accounting Policies and Estimates
|
•
|
Other Items
|
•
|
Forward-Looking Statements
|
•
|
Favorable results from our Supply and Logistics segment due to favorable crude oil grade differentials, primarily in the Permian Basin, and higher NGL margins, as well as more favorable impacts in the 2019 period from the mark-to-market of certain derivative instruments;
|
•
|
Favorable results from our Transportation segment, primarily from our pipelines in the Permian Basin region, driven by higher volumes from increased production and our recently completed capital expansion projects;
|
•
|
A non-cash gain of $267 million recognized in the current period related to a fair value adjustment resulting from the accounting for the contribution of our undivided joint interest in the Capline pipeline system for an equity interest in Capline Pipeline Company LLC;
|
•
|
The mark-to-market of our Preferred Distribution Rate Reset Option, resulting in a gain in the current period compared to a loss in the prior period; and
|
•
|
Lower income tax expense primarily due to lower year-over-year income as impacted by fluctuations in derivative mark-to market valuations in our Canadian operations, partially offset by higher taxable earnings in our Canadian operations.
|
•
|
Lowering our targeted long-term debt to Adjusted EBITDA leverage ratio by 0.5x to a range of 3.0x to 3.5x;
|
•
|
Establishing a long-term sustainable minimum annual distribution coverage level underpinned by predominantly fee-based cash flows;
|
•
|
Increasing our annualized distribution by $0.24 per common unit to $1.44 per common unit, beginning with the distribution payable May 15, 2019 to holders of record on May 1, 2019, which equates to a 20% increase from the distribution paid in February 2019; and
|
•
|
Our adoption of an annual cycle for setting the common unit distribution level and intention to increase common unit distributions in the future contingent on achieving and maintaining targeted leverage and coverage ratios and subject to an annual review process.
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Expansion capital
(1) (2)
|
$
|
351
|
|
|
$
|
298
|
|
Maintenance capital
(2)
|
46
|
|
|
45
|
|
||
|
$
|
397
|
|
|
$
|
343
|
|
|
(1)
|
Contributions to unconsolidated entities related to expansion projects of such entities are recognized in “Expansion capital.” We account for our investments in such entities under the equity method of accounting.
|
(2)
|
Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital.
|
Projects
|
|
2019
|
||
Permian Basin Takeaway Pipeline Projects
|
|
$
|
660
|
|
Complementary Permian Basin Projects
|
|
405
|
|
|
Selected Facilities
|
|
85
|
|
|
Other Projects
|
|
200
|
|
|
Total Projected 2019 Expansion Capital Expenditures
(1)
|
|
$
|
1,350
|
|
|
(1)
|
Amounts reflect our expectation that certain projects will be owned in a joint venture structure with a proportionate share of the project cost dispersed among the partners.
|
|
Three Months Ended
March 31, |
|
Variance
|
|||||||||||
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Transportation Segment Adjusted EBITDA
(1)
|
$
|
399
|
|
|
$
|
335
|
|
|
$
|
64
|
|
|
19
|
%
|
Facilities Segment Adjusted EBITDA
(1)
|
184
|
|
|
185
|
|
|
(1
|
)
|
|
(1
|
)%
|
|||
Supply and Logistics Segment Adjusted EBITDA
(1)
|
278
|
|
|
72
|
|
|
206
|
|
|
286
|
%
|
|||
Adjustments:
|
|
|
|
|
|
|
|
|||||||
Depreciation and amortization of unconsolidated entities
|
(12
|
)
|
|
(14
|
)
|
|
2
|
|
|
14
|
%
|
|||
Selected items impacting comparability - Segment Adjusted EBITDA
|
94
|
|
|
5
|
|
|
89
|
|
|
**
|
|
|||
Depreciation and amortization
|
(136
|
)
|
|
(127
|
)
|
|
(9
|
)
|
|
(7
|
)%
|
|||
Gains/(losses) on asset sales and asset impairments, net
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|
N/A
|
|
|||
Gain on investment in unconsolidated entities
|
267
|
|
|
—
|
|
|
267
|
|
|
N/A
|
|
|||
Interest expense, net
|
(101
|
)
|
|
(106
|
)
|
|
5
|
|
|
5
|
%
|
|||
Other income/(expense), net
|
25
|
|
|
(1
|
)
|
|
26
|
|
|
**
|
|
|||
Income tax expense
|
(24
|
)
|
|
(61
|
)
|
|
37
|
|
|
61
|
%
|
|||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
|
$
|
682
|
|
|
237
|
%
|
|
|
|
|
|
|
|
|
|||||||
Basic net income per common unit
|
$
|
1.26
|
|
|
$
|
0.33
|
|
|
$
|
0.93
|
|
|
**
|
|
Diluted net income per common unit
|
$
|
1.20
|
|
|
$
|
0.33
|
|
|
$
|
0.87
|
|
|
**
|
|
Basic weighted average common units outstanding
|
727
|
|
|
725
|
|
|
2
|
|
|
**
|
|
|||
Diluted weighted average common units outstanding
|
800
|
|
|
727
|
|
|
73
|
|
|
**
|
|
|
**
|
Indicates that variance as a percentage is not meaningful.
|
(1)
|
Segment Adjusted EBITDA is the measure of segment performance that is utilized by our CODM to assess performance and allocate resources among our operating segments. This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods. See
Note 14
to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
|
|
Three Months Ended
March 31, |
|
Variance
|
|||||||||||
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Net income
|
$
|
970
|
|
|
$
|
288
|
|
|
$
|
682
|
|
|
237
|
%
|
Add/(Subtract):
|
|
|
|
|
|
|
|
|
|
|||||
Interest expense, net
|
101
|
|
|
106
|
|
|
(5
|
)
|
|
(5
|
)%
|
|||
Income tax expense
|
24
|
|
|
61
|
|
|
(37
|
)
|
|
(61
|
)%
|
|||
Depreciation and amortization
|
136
|
|
|
127
|
|
|
9
|
|
|
7
|
%
|
|||
(Gains)/losses on asset sales and asset impairments, net
|
4
|
|
|
—
|
|
|
4
|
|
|
N/A
|
|
|||
Gain on investment in unconsolidated entities
|
(267
|
)
|
|
—
|
|
|
(267
|
)
|
|
N/A
|
|
|||
Depreciation and amortization of unconsolidated entities
(1)
|
12
|
|
|
14
|
|
|
(2
|
)
|
|
(14
|
)%
|
|||
Selected Items Impacting Comparability:
|
|
|
|
|
|
|
|
|
|
|||||
Gains from derivative activities, net of inventory valuation adjustments
(2)
|
(74
|
)
|
|
(23
|
)
|
|
(51
|
)
|
|
**
|
|
|||
Long-term inventory costing adjustments
(3)
|
(21
|
)
|
|
(13
|
)
|
|
(8
|
)
|
|
**
|
|
|||
Deficiencies under minimum volume commitments, net
(4)
|
(7
|
)
|
|
10
|
|
|
(17
|
)
|
|
**
|
|
|||
Equity-indexed compensation expense
(5)
|
3
|
|
|
11
|
|
|
(8
|
)
|
|
**
|
|
|||
Net loss on foreign currency revaluation
(6)
|
5
|
|
|
10
|
|
|
(5
|
)
|
|
**
|
|
|||
Selected Items Impacting Comparability - Segment Adjusted EBITDA
|
(94
|
)
|
|
(5
|
)
|
|
(89
|
)
|
|
**
|
|
|||
(Gains)/losses from derivative activities
(2)
|
(23
|
)
|
|
4
|
|
|
(27
|
)
|
|
**
|
|
|||
Net gain on foreign currency revaluation
(6)
|
(1
|
)
|
|
(2
|
)
|
|
1
|
|
|
**
|
|
|||
Selected Items Impacting Comparability - Adjusted
EBITDA (7) |
(118
|
)
|
|
(3
|
)
|
|
(115
|
)
|
|
**
|
|
|||
Adjusted EBITDA
(7)
|
$
|
862
|
|
|
$
|
593
|
|
|
$
|
269
|
|
|
45
|
%
|
Interest expense, net
(8)
|
(97
|
)
|
|
(106
|
)
|
|
9
|
|
|
8
|
%
|
|||
Maintenance capital
(9)
|
(46
|
)
|
|
(45
|
)
|
|
(1
|
)
|
|
(2
|
)%
|
|||
Current income tax expense
|
(30
|
)
|
|
(13
|
)
|
|
(17
|
)
|
|
(131
|
)%
|
|||
Adjusted equity earnings in unconsolidated entities, net of distributions
(10)
|
2
|
|
|
14
|
|
|
(12
|
)
|
|
**
|
|
|||
Implied DCF
|
$
|
691
|
|
|
$
|
443
|
|
|
248
|
|
|
56
|
%
|
|
Preferred unit distributions
(11)
|
(37
|
)
|
|
—
|
|
|
(37
|
)
|
|
N/A
|
|
|||
Implied DCF Available to Common Unitholders
|
$
|
654
|
|
|
$
|
443
|
|
|
$
|
211
|
|
|
48
|
%
|
Common unit cash distributions
(12)
|
(218
|
)
|
|
(218
|
)
|
|
|
|
|
|||||
Implied DCF Excess/(Shortage)
(13)
|
$
|
436
|
|
|
$
|
225
|
|
|
|
|
|
|
**
|
Indicates that variance as a percentage is not meaningful.
|
(1)
|
Over the past several years, we have increased our participation in strategic pipeline joint ventures, which are accounted for under the equity method of accounting. We exclude our proportionate share of the depreciation and amortization expense and gains and losses on significant asset sales by such unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
|
(2)
|
We use derivative instruments for risk management purposes, and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option. See
Note 10
to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities and our Preferred Distribution Rate Reset Option.
|
(3)
|
We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines as a selected item impacting comparability. See Note 5 to our Consolidated Financial Statements included in Part IV of our
2018
Annual Report on Form 10-K for additional inventory disclosures.
|
(4)
|
We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. 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 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. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
|
(5)
|
Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable, and the majority of the awards are expected to be settled in units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability. See Note 17 to our Consolidated Financial Statements included in Part IV of our
2018
Annual Report on Form 10-K for a comprehensive discussion regarding our equity-indexed compensation plans.
|
(6)
|
During the periods presented, there were fluctuations in the value of CAD to USD, resulting in gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability. See
Note 10
to our Condensed Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities.
|
(7)
|
Other income/(expense), net per our Condensed Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted Other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
|
(8)
|
Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.
|
(9)
|
Maintenance capital expenditures are defined as capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.
|
(10)
|
Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains and losses on significant asset sales).
|
(11)
|
Cash distributions paid to our preferred unitholders during the period presented. The current $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units was paid-in-kind for each quarterly distribution from their issuance through February 2018. Distributions on our Series A preferred units were paid in cash beginning with the May 2018 quarterly distribution. The current $61.25 per unit annual distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. See Note 12 to our Consolidated Financial Statements included in Part IV of our
2018
Annual Report on Form 10-K for additional information regarding our preferred units.
|
(12)
|
Cash distributions paid during the period presented.
|
(13)
|
Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes. DCF shortages may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.
|
Operating Results
(1)
|
|
Three Months Ended
March 31, |
|
Variance
|
|||||||||||
(in millions, except per barrel data)
|
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Revenues
|
|
$
|
556
|
|
|
$
|
454
|
|
|
$
|
102
|
|
|
22
|
%
|
Purchases and related costs
|
|
(52
|
)
|
|
(46
|
)
|
|
(6
|
)
|
|
(13
|
)%
|
|||
Field operating costs
|
|
(174
|
)
|
|
(147
|
)
|
|
(27
|
)
|
|
(18
|
)%
|
|||
Segment general and administrative expenses
(2)
|
|
(27
|
)
|
|
(28
|
)
|
|
1
|
|
|
4
|
%
|
|||
Equity earnings in unconsolidated entities
|
|
89
|
|
|
75
|
|
|
14
|
|
|
19
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Adjustments
(3)
:
|
|
|
|
|
|
|
|
|
|||||||
Depreciation and amortization of unconsolidated entities
|
|
12
|
|
|
14
|
|
|
(2
|
)
|
|
(14
|
)%
|
|||
Gains from derivative activities
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
**
|
|
|||
Deficiencies under minimum volume commitments, net
|
|
(7
|
)
|
|
8
|
|
|
(15
|
)
|
|
**
|
|
|||
Equity-indexed compensation expense
|
|
2
|
|
|
6
|
|
|
(4
|
)
|
|
**
|
|
|||
Segment Adjusted EBITDA
|
|
$
|
399
|
|
|
$
|
335
|
|
|
$
|
64
|
|
|
19
|
%
|
Maintenance capital
|
|
$
|
27
|
|
|
$
|
29
|
|
|
$
|
(2
|
)
|
|
(7
|
)%
|
Segment Adjusted EBITDA per barrel
|
|
$
|
0.68
|
|
|
$
|
0.70
|
|
|
$
|
(0.02
|
)
|
|
(3
|
)%
|
Average Daily Volumes
|
|
Three Months Ended
March 31, |
|
Variance
|
||||||||
(in thousands of barrels per day)
(4)
|
|
2019
|
|
2018
|
|
Volumes
|
|
%
|
||||
Tariff activities volumes
|
|
|
|
|
|
|
|
|
||||
Crude oil pipelines (by region):
|
|
|
|
|
|
|
|
|
||||
Permian Basin
(5)
|
|
4,268
|
|
|
3,240
|
|
|
1,028
|
|
|
32
|
%
|
South Texas / Eagle Ford
(5)
|
|
460
|
|
|
422
|
|
|
38
|
|
|
9
|
%
|
Central
(5)
|
|
509
|
|
|
441
|
|
|
68
|
|
|
15
|
%
|
Gulf Coast
|
|
158
|
|
|
204
|
|
|
(46
|
)
|
|
(23
|
)%
|
Rocky Mountain
(5)
|
|
302
|
|
|
257
|
|
|
45
|
|
|
18
|
%
|
Western
|
|
182
|
|
|
174
|
|
|
8
|
|
|
5
|
%
|
Canada
|
|
322
|
|
|
318
|
|
|
4
|
|
|
1
|
%
|
Crude oil pipelines
|
|
6,201
|
|
|
5,056
|
|
|
1,145
|
|
|
23
|
%
|
NGL pipelines
|
|
210
|
|
|
173
|
|
|
37
|
|
|
21
|
%
|
Tariff activities total volumes
|
|
6,411
|
|
|
5,229
|
|
|
1,182
|
|
|
23
|
%
|
Trucking volumes
|
|
93
|
|
|
99
|
|
|
(6
|
)
|
|
(6
|
)%
|
Transportation segment total volumes
|
|
6,504
|
|
|
5,328
|
|
|
1,176
|
|
|
22
|
%
|
|
**
|
Indicates that variance as a percentage is not meaningful.
|
(1)
|
Revenues and costs and expenses include intersegment amounts.
|
(2)
|
Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
|
(3)
|
Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See
Note 14
to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
|
(4)
|
Average daily volumes are calculated as the total volumes (attributable to our interest) for the period divided by the number of days in the period.
|
(5)
|
Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.
|
|
|
Favorable/(Unfavorable) Variance
Three Months Ended March 31, 2019-2018 |
||||||||||
(in millions)
|
|
Revenues
|
|
Purchases and
Related Costs |
|
Equity
Earnings |
||||||
Permian Basin region
|
|
$
|
66
|
|
|
$
|
(2
|
)
|
|
$
|
(11
|
)
|
South Texas / Eagle Ford region
|
|
2
|
|
|
—
|
|
|
21
|
|
|||
Central region
|
|
15
|
|
|
—
|
|
|
4
|
|
|||
Other regions, trucking and pipeline loss allowance revenue
|
|
19
|
|
|
(4
|
)
|
|
—
|
|
|||
Total variance
|
|
$
|
102
|
|
|
$
|
(6
|
)
|
|
$
|
14
|
|
•
|
Permian Basin region.
The increase in revenues, net of purchases and related costs, of approximately $64 million was primarily due to higher volumes from increased production and our recently completed capital expansion projects. These increases included (i) higher volumes on our gathering systems of approximately 301,000 barrels per day, (ii) higher volumes of approximately 510,000 barrels per day on our intra-basin pipelines and (iii) a volume increase of approximately 217,000 on our long-haul pipelines, including our Sunrise II pipeline, which was placed in service in the fourth quarter of 2018.
|
•
|
South Texas / Eagle Ford region.
The increase in equity earnings was from our 50% interest in Eagle Ford Pipeline LLC due to the recognition of revenue associated with deficiencies under minimum volume commitments and higher volumes from our Cactus pipeline.
|
•
|
Central region.
The increase in revenues was primarily due to the recognition of previously deferred revenue, as well as higher volumes on certain of our pipelines in the Central region.
|
•
|
Other regions, trucking and pipeline loss allowance revenue.
The increase in other net revenues was primarily due to (i) greater loss allowance revenue driven by higher volumes and prices in the 2019 period and (ii) higher tariffs on certain of our Canadian pipelines, partially offset by the sale of certain of our assets in the Rocky Mountain region in the second quarter of 2018. The decrease in volumes in the Gulf Coast region were associated with (i) a lower tariff pipeline, which did not result in a significant impact on revenue and (ii) the Capline pipeline being taken out of service in the fourth quarter of 2018. We are currently pursuing an opportunity to reverse the flow of the Capline pipeline.
|
Operating Results
(1)
|
|
Three Months Ended
March 31, |
|
Variance
|
|||||||||||
(in millions, except per barrel data)
|
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Revenues
|
|
$
|
299
|
|
|
$
|
292
|
|
|
$
|
7
|
|
|
2
|
%
|
Purchases and related costs
|
|
(4
|
)
|
|
(5
|
)
|
|
1
|
|
|
20
|
%
|
|||
Field operating costs
|
|
(86
|
)
|
|
(84
|
)
|
|
(2
|
)
|
|
(2
|
)%
|
|||
Segment general and administrative expenses
(2)
|
|
(21
|
)
|
|
(21
|
)
|
|
—
|
|
|
—
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Adjustments
(3)
:
|
|
|
|
|
|
|
|
|
|||||||
Gains from derivative activities
|
|
(4
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
**
|
|
|||
Deficiencies under minimum volume commitments, net
|
|
—
|
|
|
2
|
|
|
(2
|
)
|
|
**
|
|
|||
Equity-indexed compensation expense
|
|
—
|
|
|
2
|
|
|
(2
|
)
|
|
**
|
|
|||
Segment Adjusted EBITDA
|
|
$
|
184
|
|
|
$
|
185
|
|
|
$
|
(1
|
)
|
|
(1
|
)%
|
Maintenance capital
|
|
$
|
17
|
|
|
$
|
14
|
|
|
$
|
3
|
|
|
21
|
%
|
Segment Adjusted EBITDA per barrel
|
|
$
|
0.49
|
|
|
$
|
0.50
|
|
|
$
|
(0.01
|
)
|
|
(2
|
)%
|
|
|
Three Months Ended
March 31, |
|
Variance
|
||||||||
Volumes
(4)
|
|
2019
|
|
2018
|
|
Volumes
|
|
%
|
||||
Liquids storage (average monthly capacity in millions of barrels)
|
|
109
|
|
|
109
|
|
|
—
|
|
|
—
|
%
|
Natural gas storage (average monthly working capacity in billions of cubic feet)
(5)
|
|
63
|
|
|
67
|
|
|
(4
|
)
|
|
(6
|
)%
|
NGL fractionation (average volumes in thousands of barrels per day)
|
|
157
|
|
|
138
|
|
|
19
|
|
|
14
|
%
|
Facilities segment total volumes (average monthly volumes in millions of barrels)
(6)
|
|
124
|
|
|
124
|
|
|
—
|
|
|
—
|
%
|
|
**
|
Indicates that variance as a percentage is not meaningful.
|
(1)
|
Revenues and costs and expenses include intersegment amounts.
|
(2)
|
Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
|
(3)
|
Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See
Note 14
to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
|
(4)
|
Average monthly volumes are calculated as total volumes for the period divided by the number of months in the period.
|
(5)
|
The decrease in average monthly working capacity of natural gas storage facilities was driven by adjustments for the net capacity change between capacity additions from fill and dewater operations and capacity losses from salt creep.
|
(6)
|
Facilities segment total volumes is calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.
|
•
|
Crude Oil Storage.
Revenues increased by $7 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 due to increased activity at certain of our terminals, primarily our Cushing terminal.
|
•
|
Rail Terminals.
Revenues increased by $6 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to higher activity at certain of our rail terminals resulting from more favorable market conditions.
|
•
|
Natural Gas Storage.
Revenues, net of purchases and related costs, increased by $4 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 due to expiring contracts replaced by contracts with higher rates at our Pine Prairie facility.
|
•
|
NGL Operations.
Revenues decreased by $11 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 primarily due to a net unfavorable foreign exchange impact of approximately $6 million and the sale of a natural gas processing facility in the second quarter of 2018.
|
Operating Results
(1)
|
|
Three Months Ended
March 31, |
|
Variance
|
|||||||||||
(in millions, except per barrel data)
|
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Revenues
|
|
$
|
8,022
|
|
|
$
|
8,112
|
|
|
$
|
(90
|
)
|
|
(1
|
)%
|
Purchases and related costs
|
|
(7,562
|
)
|
|
(7,925
|
)
|
|
363
|
|
|
5
|
%
|
|||
Field operating costs
|
|
(69
|
)
|
|
(64
|
)
|
|
(5
|
)
|
|
(8
|
)%
|
|||
Segment general and administrative expenses
(2)
|
|
(28
|
)
|
|
(30
|
)
|
|
2
|
|
|
7
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Adjustments
(3)
:
|
|
|
|
|
|
|
|
|
|||||||
Gains from derivative activities net of inventory valuation adjustments
|
|
(70
|
)
|
|
(21
|
)
|
|
(49
|
)
|
|
**
|
|
|||
Long-term inventory costing adjustments
|
|
(21
|
)
|
|
(13
|
)
|
|
(8
|
)
|
|
**
|
|
|||
Equity-indexed compensation expense
|
|
1
|
|
|
3
|
|
|
(2
|
)
|
|
**
|
|
|||
Net loss on foreign currency revaluation
|
|
5
|
|
|
10
|
|
|
(5
|
)
|
|
**
|
|
|||
Segment Adjusted EBITDA
|
|
$
|
278
|
|
|
$
|
72
|
|
|
$
|
206
|
|
|
286
|
%
|
Maintenance capital
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
—
|
%
|
Segment Adjusted EBITDA per barrel
|
|
$
|
2.12
|
|
|
$
|
0.57
|
|
|
$
|
1.55
|
|
|
272
|
%
|
Average Daily Volumes
(4)
|
|
Three Months Ended
March 31, |
|
Variance
|
||||||||
(in thousands of barrels per day)
|
|
2019
|
|
2018
|
|
Volumes
|
|
%
|
||||
Crude oil lease gathering purchases
|
|
1,128
|
|
|
1,031
|
|
|
97
|
|
|
9
|
%
|
NGL sales
|
|
328
|
|
|
361
|
|
|
(33
|
)
|
|
(9
|
)%
|
Supply and Logistics segment total volumes
|
|
1,456
|
|
|
1,392
|
|
|
64
|
|
|
5
|
%
|
|
**
|
Indicates that variance as a percentage is not meaningful.
|
(1)
|
Revenues and costs include intersegment amounts.
|
(2)
|
Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
|
(3)
|
Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See
Note 14
to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
|
(4)
|
Average daily volumes are calculated as the total volumes for the period divided by the number of days in the period.
|
|
NYMEX WTI
Crude Oil Price |
||||||
|
Low
|
|
High
|
||||
Three months ended March 31, 2019
|
$
|
47
|
|
|
$
|
60
|
|
Three months ended March 31, 2018
|
$
|
59
|
|
|
$
|
66
|
|
•
|
Crude Oil Operations.
Net revenues from our crude oil supply and logistics operations increased for the
three
months ended
March 31, 2019
compared to the
three
months ended
March 31, 2018
largely due to favorable grade differentials, primarily in the Permian Basin.
|
•
|
NGL Operations.
Net revenues from our NGL operations increased for the
three
months ended
March 31, 2019
compared to the same period in
2018
primarily due to the streamlining of our NGL activities by focusing on our equity supply from our gathering and processing facilities, and by reducing the volume of third party purchases.
|
•
|
Impact from Certain Derivative Activities Net of Inventory Valuation Adjustments.
The impact from certain derivative activities on our net revenues includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See
Note 10
to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.
|
•
|
Long-Term Inventory Costing Adjustments.
Our net revenues are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. These costing adjustments impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.
|
•
|
Foreign Exchange Impacts.
Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in foreign exchange gains and losses on U.S. denominated net assets within our Canadian operations. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.
|
•
|
Field Operating Costs.
The increase in field operating costs for the
three
months ended
March 31, 2019
compared to the
three
months ended
March 31, 2018
was primarily driven by an increase in trucking costs resulting from higher third-party hauled volumes, partially offset by a decrease in vehicle expense related to the adoption of the new lease accounting standard.
|
|
Three Months Ended
March 31, |
||||||
|
2019
|
|
2018
|
||||
Gain/(loss) related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option
(1)
|
$
|
23
|
|
|
$
|
(4
|
)
|
Other
|
2
|
|
|
3
|
|
||
|
$
|
25
|
|
|
$
|
(1
|
)
|
|
(1)
|
See
Note 10
to our Condensed Consolidated Financial Statements for additional information.
|
|
As of
March 31, 2019 |
||
Availability under senior unsecured revolving credit facility
(1) (2)
|
$
|
1,462
|
|
Availability under senior secured hedged inventory facility
(1) (2)
|
1,383
|
|
|
Subtotal
|
2,845
|
|
|
Cash and cash equivalents
|
436
|
|
|
Total
|
$
|
3,281
|
|
|
(1)
|
Amounts outstanding under our commercial paper program reduce available capacity under the facilities. There were no outstanding commercial paper borrowings at March 31, 2019.
|
(2)
|
Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit of
$138 million
and
$17 million
, respectively.
|
|
Remainder of 2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024 and Thereafter
|
|
Total
|
||||||||||||||
Long-term debt and related interest payments
(1)
|
$
|
814
|
|
|
$
|
878
|
|
|
$
|
949
|
|
|
$
|
1,079
|
|
|
$
|
1,599
|
|
|
$
|
8,593
|
|
|
$
|
13,912
|
|
Leases
(2)
|
107
|
|
|
124
|
|
|
95
|
|
|
83
|
|
|
57
|
|
|
251
|
|
|
717
|
|
|||||||
Other obligations
(3)
|
799
|
|
|
566
|
|
|
288
|
|
|
256
|
|
|
238
|
|
|
1,177
|
|
|
3,324
|
|
|||||||
Subtotal
|
1,720
|
|
|
1,568
|
|
|
1,332
|
|
|
1,418
|
|
|
1,894
|
|
|
10,021
|
|
|
17,953
|
|
|||||||
Crude oil, NGL and other purchases
(4)
|
7,643
|
|
|
7,488
|
|
|
6,997
|
|
|
6,607
|
|
|
6,096
|
|
|
13,570
|
|
|
48,401
|
|
|||||||
Total
|
$
|
9,363
|
|
|
$
|
9,056
|
|
|
$
|
8,329
|
|
|
$
|
8,025
|
|
|
$
|
7,990
|
|
|
$
|
23,591
|
|
|
$
|
66,354
|
|
|
(1)
|
Includes debt service payments, interest payments due on senior notes and the commitment fee on assumed available capacity under our credit facilities, as well as long-term borrowings under our credit agreements and commercial paper program, if any. Although there may be short-term borrowings under our credit agreements and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the credit agreements or commercial paper program) in the amounts above. For additional information regarding our debt obligations, see
Note 8
to our Condensed Consolidated Financial Statements.
|
(2)
|
Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) office space, (iii), land, (iv) vehicles, (v) storage tanks and (vi) tractor trailers. See
Note 11
to our Condensed Consolidated Financial Statements for additional information.
|
(3)
|
Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements (including certain agreements for which the amount and timing of expected payments is subject to the completion of underlying construction projects), (iii) certain rights-of-way easements and (iv) noncancelable commitments related to our capital expansion projects, including projected contributions for our share of the capital spending of our equity method investments. The transportation agreements include approximately $1.7 billion associated with agreements to transport crude oil at posted tariff rates on pipelines that are owned by equity method investees. Our commitment to transport is supported by crude oil buy/sell or other agreements with third parties (including Oxy) with commensurate quantities.
|
(4)
|
Amounts are primarily based on estimated volumes and market prices based on average activity during
March
2019
. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.
|
•
|
declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, reduced demand, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors;
|
•
|
the effects of competition, including the effects of capacity overbuild in areas where we operate;
|
•
|
market distortions caused by over-commitments to infrastructure projects, which impacts volumes, margins, returns and overall earnings;
|
•
|
unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
|
•
|
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
|
•
|
fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, NGL and natural gas and resulting changes in pricing conditions or transportation throughput requirements;
|
•
|
maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;
|
•
|
the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including cyber or other attacks on our electronic and computer systems;
|
•
|
failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects, whether due to permitting delays, permitting withdrawals or other factors;
|
•
|
shortages or cost increases of supplies, materials or labor;
|
•
|
the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations;
|
•
|
tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;
|
•
|
the availability of, and our ability to consummate, acquisition or combination opportunities;
|
•
|
the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;
|
•
|
the currency exchange rate of the Canadian dollar;
|
•
|
continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;
|
•
|
inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used;
|
•
|
non-utilization of our assets and facilities;
|
•
|
increased costs, or lack of availability, of insurance;
|
•
|
weather interference with business operations or project construction, including the impact of extreme weather events or conditions;
|
•
|
the effectiveness of our risk management activities;
|
•
|
fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;
|
•
|
risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers;
|
•
|
general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and
|
•
|
other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.
|
|
Fair Value
|
|
Effect of 10%
Price Increase |
|
Effect of 10%
Price Decrease |
||||||
Crude oil
|
$
|
336
|
|
|
$
|
(29
|
)
|
|
$
|
33
|
|
Natural gas
|
(12
|
)
|
|
$
|
6
|
|
|
$
|
(6
|
)
|
|
NGL and other
|
29
|
|
|
$
|
(15
|
)
|
|
$
|
15
|
|
|
Total fair value
|
$
|
353
|
|
|
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
|
3.1
|
—
|
|
|
|
|
3.2
|
—
|
|
|
|
|
3.3
|
—
|
|
|
|
|
3.4
|
—
|
|
|
|
|
3.5
|
—
|
|
|
|
|
3.6
|
—
|
|
|
|
|
3.7
|
—
|
|
|
|
|
3.8
|
—
|
|
|
|
|
3.9
|
—
|
|
|
|
|
3.10
|
—
|
|
|
|
|
3.11
|
—
|
|
|
|
|
3.12
|
—
|
|
|
|
|
3.13
|
—
|
|
|
|
|
3.14
|
—
|
|
|
|
|
3.15
|
—
|
|
|
|
|
3.16
|
—
|
|
|
|
|
3.17
|
—
|
|
|
|
|
3.18
|
—
|
|
|
|
|
3.19
|
—
|
|
|
|
|
3.20
|
—
|
|
|
|
|
4.1
|
—
|
|
|
|
|
4.2
|
—
|
|
|
|
|
4.3
|
—
|
|
|
|
|
4.4
|
—
|
|
|
|
|
4.5
|
—
|
|
|
|
|
4.6
|
—
|
|
|
|
|
4.7
|
—
|
|
|
|
|
4.8
|
—
|
|
|
|
|
4.9
|
—
|
|
|
|
|
4.10
|
—
|
|
|
|
|
4.11
|
—
|
|
|
|
|
4.12
|
—
|
|
|
|
|
4.13
|
—
|
|
|
|
|
4.14
|
—
|
|
|
|
|
4.15
|
—
|
|
|
|
|
4.16
|
—
|
|
|
|
|
4.17
|
—
|
|
|
|
|
4.18
|
—
|
|
|
|
|
4.19
|
—
|
|
|
|
|
31.1 †
|
—
|
|
|
|
|
31.2 †
|
—
|
|
|
|
|
32.1 ††
|
—
|
|
|
|
|
32.2 ††
|
—
|
|
|
|
|
101.INS†
|
—
|
XBRL Instance Document
|
|
|
|
101.SCH†
|
—
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
101.CAL†
|
—
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
101.DEF†
|
—
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
101.LAB†
|
—
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
101.PRE†
|
—
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
†
|
Filed herewith.
|
††
|
Furnished herewith.
|
|
PLAINS ALL AMERICAN PIPELINE, L.P.
|
|
|
|
|
|
By:
|
PAA GP LLC,
|
|
|
its general partner
|
|
|
|
|
By:
|
Plains AAP, L.P.,
|
|
|
its sole member
|
|
|
|
|
By:
|
PLAINS ALL AMERICAN GP LLC,
|
|
|
its general partner
|
|
|
|
|
By:
|
/s/ Willie Chiang
|
|
|
Willie Chiang,
|
|
|
Chief Executive Officer of Plains All American GP LLC
|
|
|
(Principal Executive Officer)
|
|
|
|
May 9, 2019
|
|
|
|
|
|
|
By:
|
/s/ Al Swanson
|
|
|
Al Swanson,
|
|
|
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
|
|
|
(Principal Financial Officer)
|
|
|
|
May 9, 2019
|
|
|
|
|
|
|
By:
|
/s/ Chris Herbold
|
|
|
Chris Herbold,
|
|
|
Senior Vice President and Chief Accounting Officer of Plains All American GP LLC
|
|
|
(Principal Accounting Officer)
|
|
|
|
May 9, 2019
|
|
1 Year Plains All American Pipe... Chart |
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