We could not find any results for:
Make sure your spelling is correct or try broadening your search.
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
|
|
(I.R.S. Employer
|
incorporation or organization)
|
|
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
|
|
|
|
(Do not check if a smaller reporting company)
|
|
Emerging growth company
o
|
|
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(unaudited)
|
|
(unaudited)
|
||||||||||||
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
||||
Supply and Logistics segment revenues
|
$
|
8,482
|
|
|
$
|
5,573
|
|
|
$
|
24,374
|
|
|
$
|
17,749
|
|
Transportation segment revenues
|
161
|
|
|
160
|
|
|
458
|
|
|
459
|
|
||||
Facilities segment revenues
|
149
|
|
|
140
|
|
|
437
|
|
|
410
|
|
||||
Total revenues
|
8,792
|
|
|
5,873
|
|
|
25,269
|
|
|
18,618
|
|
||||
|
|
|
|
|
|
|
|
||||||||
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
||||
Purchases and related costs
|
7,768
|
|
|
5,327
|
|
|
22,838
|
|
|
16,239
|
|
||||
Field operating costs
|
326
|
|
|
283
|
|
|
931
|
|
|
876
|
|
||||
General and administrative expenses
|
74
|
|
|
68
|
|
|
232
|
|
|
210
|
|
||||
Depreciation and amortization
|
131
|
|
|
151
|
|
|
306
|
|
|
401
|
|
||||
Total costs and expenses
|
8,299
|
|
|
5,829
|
|
|
24,307
|
|
|
17,726
|
|
||||
|
|
|
|
|
|
|
|
||||||||
OPERATING INCOME
|
493
|
|
|
44
|
|
|
962
|
|
|
892
|
|
||||
|
|
|
|
|
|
|
|
||||||||
OTHER INCOME/(EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
||||
Equity earnings in unconsolidated entities
|
110
|
|
|
80
|
|
|
281
|
|
|
201
|
|
||||
Gain on sale of investment in unconsolidated entities
|
210
|
|
|
—
|
|
|
210
|
|
|
—
|
|
||||
Interest expense (net of capitalized interest of $8, $11, $21 and $26, respectively)
|
(110
|
)
|
|
(134
|
)
|
|
(327
|
)
|
|
(390
|
)
|
||||
Other income/(expense), net
|
(3
|
)
|
|
(1
|
)
|
|
8
|
|
|
(6
|
)
|
||||
|
|
|
|
|
|
|
|
||||||||
INCOME/(LOSS) BEFORE TAX
|
700
|
|
|
(11
|
)
|
|
1,134
|
|
|
697
|
|
||||
Current income tax (expense)/benefit
|
(14
|
)
|
|
1
|
|
|
(34
|
)
|
|
(9
|
)
|
||||
Deferred income tax (expense)/benefit
|
24
|
|
|
44
|
|
|
(1
|
)
|
|
(21
|
)
|
||||
|
|
|
|
|
|
|
|
||||||||
NET INCOME
|
710
|
|
|
34
|
|
|
1,099
|
|
|
667
|
|
||||
Net income attributable to noncontrolling interests
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(2
|
)
|
||||
NET INCOME ATTRIBUTABLE TO PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
$
|
1,099
|
|
|
$
|
665
|
|
|
|
|
|
|
|
|
|
||||||||
NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income/(loss) allocated to common unitholders — Basic
|
$
|
658
|
|
|
$
|
(8
|
)
|
|
$
|
946
|
|
|
$
|
547
|
|
Basic weighted average common units outstanding
|
726
|
|
|
725
|
|
|
726
|
|
|
714
|
|
||||
Basic net income/(loss) per common unit
|
$
|
0.91
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.30
|
|
|
$
|
0.77
|
|
|
|
|
|
|
|
|
|
||||||||
Net income/(loss) allocated to common unitholders — Diluted
|
$
|
697
|
|
|
$
|
(8
|
)
|
|
$
|
947
|
|
|
$
|
547
|
|
Diluted weighted average common units outstanding
|
799
|
|
|
725
|
|
|
728
|
|
|
715
|
|
||||
Diluted net income/(loss) per common unit
|
$
|
0.87
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.30
|
|
|
$
|
0.76
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(unaudited)
|
|
(unaudited)
|
||||||||||||
Net income
|
$
|
710
|
|
|
$
|
34
|
|
|
$
|
1,099
|
|
|
$
|
667
|
|
Other comprehensive income/(loss)
|
76
|
|
|
145
|
|
|
(46
|
)
|
|
256
|
|
||||
Comprehensive income
|
786
|
|
|
179
|
|
|
1,053
|
|
|
923
|
|
||||
Comprehensive income attributable to noncontrolling interests
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(2
|
)
|
||||
Comprehensive income attributable to PAA
|
$
|
786
|
|
|
$
|
178
|
|
|
$
|
1,053
|
|
|
$
|
921
|
|
|
Derivative
Instruments |
|
Translation
Adjustments |
|
Other
|
|
Total
|
||||||||
|
(unaudited)
|
||||||||||||||
Balance at December 31, 2017
|
$
|
(223
|
)
|
|
$
|
(548
|
)
|
|
$
|
1
|
|
|
$
|
(770
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
||||
Unrealized gain on hedges
|
60
|
|
|
—
|
|
|
—
|
|
|
60
|
|
||||
Currency translation adjustments
|
—
|
|
|
(112
|
)
|
|
—
|
|
|
(112
|
)
|
||||
Total period activity
|
66
|
|
|
(112
|
)
|
|
—
|
|
|
(46
|
)
|
||||
Balance at September 30, 2018
|
$
|
(157
|
)
|
|
$
|
(660
|
)
|
|
$
|
1
|
|
|
$
|
(816
|
)
|
|
Derivative
Instruments |
|
Translation
Adjustments |
|
Other
|
|
Total
|
||||||||
|
(unaudited)
|
||||||||||||||
Balance at December 31, 2016
|
$
|
(228
|
)
|
|
$
|
(782
|
)
|
|
$
|
1
|
|
|
$
|
(1,009
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
19
|
|
|
—
|
|
|
—
|
|
|
19
|
|
||||
Unrealized loss on hedges
|
(15
|
)
|
|
—
|
|
|
—
|
|
|
(15
|
)
|
||||
Currency translation adjustments
|
—
|
|
|
252
|
|
|
—
|
|
|
252
|
|
||||
Total period activity
|
4
|
|
|
252
|
|
|
—
|
|
|
256
|
|
||||
Balance at September 30, 2017
|
$
|
(224
|
)
|
|
$
|
(530
|
)
|
|
$
|
1
|
|
|
$
|
(753
|
)
|
|
Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
|
(unaudited)
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
||
Net income
|
$
|
1,099
|
|
|
$
|
667
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
|
|
||
Depreciation and amortization
|
306
|
|
|
401
|
|
||
Equity-indexed compensation expense
|
59
|
|
|
33
|
|
||
Inventory valuation adjustments
|
—
|
|
|
35
|
|
||
Deferred income tax expense
|
1
|
|
|
21
|
|
||
(Gain)/loss on foreign currency revaluation
|
2
|
|
|
(20
|
)
|
||
Settlement of terminated interest rate hedging instruments
|
14
|
|
|
(29
|
)
|
||
Equity earnings in unconsolidated entities
|
(281
|
)
|
|
(201
|
)
|
||
Distributions on earnings from unconsolidated entities
|
324
|
|
|
222
|
|
||
Gain on sale of investment in unconsolidated entities
|
(210
|
)
|
|
—
|
|
||
Other
|
17
|
|
|
19
|
|
||
Changes in assets and liabilities, net of acquisitions
|
(37
|
)
|
|
770
|
|
||
Net cash provided by operating activities
|
1,294
|
|
|
1,918
|
|
||
|
|
|
|
||||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
||
Cash paid in connection with acquisitions, net of cash acquired
|
—
|
|
|
(1,282
|
)
|
||
Investments in unconsolidated entities
|
(300
|
)
|
|
(356
|
)
|
||
Additions to property, equipment and other
|
(1,184
|
)
|
|
(778
|
)
|
||
Proceeds from sales of assets
|
1,298
|
|
|
407
|
|
||
Return of investment from unconsolidated entities
|
10
|
|
|
21
|
|
||
Other investing activities
|
(8
|
)
|
|
25
|
|
||
Net cash used in investing activities
|
(184
|
)
|
|
(1,963
|
)
|
||
|
|
|
|
||||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
||
Net repayments under commercial paper program (Note 9)
|
(63
|
)
|
|
(115
|
)
|
||
Net borrowings/(repayments) under senior secured hedged inventory facility (Note 9)
|
(479
|
)
|
|
7
|
|
||
Proceeds from GO Zone term loans (Note 9)
|
200
|
|
|
—
|
|
||
Repayments of senior notes
|
—
|
|
|
(400
|
)
|
||
Net proceeds from sales of common units
|
—
|
|
|
1,664
|
|
||
Distributions paid to Series A preferred unitholders (Note 10)
|
(75
|
)
|
|
—
|
|
||
Distributions paid to Series B preferred unitholders (Note 10)
|
(25
|
)
|
|
—
|
|
||
Distributions paid to common unitholders (Note 10)
|
(653
|
)
|
|
(1,168
|
)
|
||
Other financing activities
|
(20
|
)
|
|
41
|
|
||
Net cash provided by/(used in) financing activities
|
(1,115
|
)
|
|
29
|
|
||
|
|
|
|
||||
Effect of translation adjustment on cash
|
(3
|
)
|
|
2
|
|
||
|
|
|
|
||||
Net decrease in cash and cash equivalents
|
(8
|
)
|
|
(14
|
)
|
||
Cash and cash equivalents, beginning of period
|
37
|
|
|
47
|
|
||
Cash and cash equivalents, end of period
|
$
|
29
|
|
|
$
|
33
|
|
|
|
|
|
||||
Cash paid for:
|
|
|
|
|
|
||
Interest, net of amounts capitalized
|
$
|
281
|
|
|
$
|
325
|
|
Income taxes, net of amounts refunded
|
$
|
20
|
|
|
$
|
47
|
|
|
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
|
|
||||
Balance at January 1, 2018
|
1,505
|
|
|
788
|
|
|
8,778
|
|
|
11,071
|
|
||||
Net income
|
112
|
|
|
37
|
|
|
950
|
|
|
1,099
|
|
||||
Distributions (Note 10)
|
(112
|
)
|
|
(37
|
)
|
|
(653
|
)
|
|
(802
|
)
|
||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
(46
|
)
|
|
(46
|
)
|
||||
Equity-indexed compensation expense
|
—
|
|
|
—
|
|
|
37
|
|
|
37
|
|
||||
Other
|
—
|
|
|
(1
|
)
|
|
(8
|
)
|
|
(9
|
)
|
||||
Balance at September 30, 2018
|
$
|
1,505
|
|
|
$
|
787
|
|
|
$
|
9,058
|
|
|
$
|
11,350
|
|
|
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
|
—
|
|
|
665
|
|
|
665
|
|
|
2
|
|
|
667
|
|
|||||
Distributions
|
—
|
|
|
(1,168
|
)
|
|
(1,168
|
)
|
|
(2
|
)
|
|
(1,170
|
)
|
|||||
Sales of common units
|
—
|
|
|
1,664
|
|
|
1,664
|
|
|
—
|
|
|
1,664
|
|
|||||
Acquisition of interest in Advantage Joint Venture
|
—
|
|
|
40
|
|
|
40
|
|
|
—
|
|
|
40
|
|
|||||
Other comprehensive income
|
—
|
|
|
256
|
|
|
256
|
|
|
—
|
|
|
256
|
|
|||||
Equity-indexed compensation expense
|
—
|
|
|
18
|
|
|
18
|
|
|
|
|
18
|
|
||||||
Other
|
(2
|
)
|
|
(9
|
)
|
|
(11
|
)
|
|
—
|
|
|
(11
|
)
|
|||||
Balance at September 30, 2017
|
$
|
1,506
|
|
|
$
|
8,717
|
|
|
$
|
10,223
|
|
|
$
|
57
|
|
|
$
|
10,280
|
|
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
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
||||
Supply and Logistics segment revenues from contracts with customers
|
|
|
|
||||
Crude oil transactions
|
$
|
7,978
|
|
|
$
|
22,651
|
|
NGL and other transactions
|
556
|
|
|
2,181
|
|
||
Total Supply and Logistics segment revenues from contracts with customers
|
$
|
8,534
|
|
|
$
|
24,832
|
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
||||
Transportation segment revenues from contracts with customers
|
|
|
|
||||
Tariff activities:
|
|
|
|
||||
Crude oil pipelines
|
$
|
435
|
|
|
$
|
1,237
|
|
NGL pipelines
|
25
|
|
|
76
|
|
||
Total tariff activities
|
460
|
|
|
1,313
|
|
||
Trucking
|
36
|
|
|
103
|
|
||
Total Transportation segment revenues from contracts with customers
|
$
|
496
|
|
|
$
|
1,416
|
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
||||
Facilities segment revenues from contracts with customers
|
|
|
|
||||
Crude oil, NGL and other terminalling and storage
|
$
|
174
|
|
|
$
|
511
|
|
NGL and natural gas processing and fractionation
|
87
|
|
|
278
|
|
||
Rail load / unload
|
24
|
|
|
56
|
|
||
Total Facilities segment revenues from contracts with customers
|
$
|
285
|
|
|
$
|
845
|
|
Three Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Total
|
||||||||
Revenues from contracts with customers
|
|
$
|
496
|
|
|
$
|
285
|
|
|
$
|
8,534
|
|
|
$
|
9,315
|
|
Other items in revenues
|
|
2
|
|
|
4
|
|
|
(51
|
)
|
|
(45
|
)
|
||||
Total revenues of reportable segments
|
|
$
|
498
|
|
|
$
|
289
|
|
|
$
|
8,483
|
|
|
$
|
9,270
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
(478
|
)
|
|||||||
Total revenues
|
|
|
|
|
|
|
|
$
|
8,792
|
|
Nine Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Total
|
||||||||
Revenues from contracts with customers
|
|
$
|
1,416
|
|
|
$
|
845
|
|
|
$
|
24,832
|
|
|
$
|
27,093
|
|
Other items in revenues
|
|
11
|
|
|
21
|
|
|
(456
|
)
|
|
(424
|
)
|
||||
Total revenues of reportable segments
|
|
$
|
1,427
|
|
|
$
|
866
|
|
|
$
|
24,376
|
|
|
$
|
26,669
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
(1,400
|
)
|
|||||||
Total revenues
|
|
|
|
|
|
|
|
$
|
25,269
|
|
|
September 30,
2018 |
|
December 31, 2017
|
||||
Trade accounts receivable arising from revenues from contracts with customers
|
$
|
2,910
|
|
|
$
|
2,584
|
|
Other trade accounts receivables and other receivables
(1)
|
3,482
|
|
|
3,709
|
|
||
Impact due to contractual rights of offset with counterparties
|
(3,438
|
)
|
|
(3,264
|
)
|
||
Trade accounts receivable and other receivables, net
|
$
|
2,954
|
|
|
$
|
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.
|
|
|
Contract Liabilities
|
||
Balance at December 31, 2017
|
|
$
|
90
|
|
Amounts recognized as revenue
|
|
(78
|
)
|
|
Additions
(1) (2)
|
|
384
|
|
|
Other
|
|
(3
|
)
|
|
Balance at September 30, 2018
|
|
$
|
393
|
|
|
(1)
|
Includes approximately
$159 million
associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the
fourth quarter of 2018
.
|
(2)
|
Includes
$100 million
associated with long-term capacity agreements with Cactus II Pipeline LLC. See
Note 12
for additional information.
|
|
Remainder of 2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 and Thereafter
|
||||||||||||
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements
(1)
|
$
|
34
|
|
|
$
|
158
|
|
|
$
|
199
|
|
|
$
|
190
|
|
|
$
|
188
|
|
|
$
|
831
|
|
Long-term storage, terminalling and throughput agreements revenues
|
118
|
|
|
374
|
|
|
296
|
|
|
214
|
|
|
162
|
|
|
573
|
|
||||||
Total
|
$
|
152
|
|
|
$
|
532
|
|
|
$
|
495
|
|
|
$
|
404
|
|
|
$
|
350
|
|
|
$
|
1,404
|
|
|
(1)
|
Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects.
|
•
|
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, Diamond and Cactus II 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 — Contracts include 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
.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Basic Net Income/(Loss) per Common Unit
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
1,099
|
|
|
665
|
|
||
Distributions to Series A preferred unitholders
|
(37
|
)
|
|
(36
|
)
|
|
(112
|
)
|
|
(105
|
)
|
||||
Distributions to Series B preferred unitholders
|
(12
|
)
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
||||
Distributions to participating securities
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
||||
Other
|
(2
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|
(11
|
)
|
||||
Net income/(loss) allocated to common unitholders
(1)
|
$
|
658
|
|
|
$
|
(8
|
)
|
|
$
|
946
|
|
|
$
|
547
|
|
|
|
|
|
|
|
|
|
||||||||
Basic weighted average common units outstanding
|
726
|
|
|
725
|
|
|
726
|
|
|
714
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Basic net income/(loss) per common unit
|
$
|
0.91
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.30
|
|
|
$
|
0.77
|
|
|
|
|
|
|
|
|
|
||||||||
Diluted Net Income/(Loss) per Common Unit
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
$
|
1,099
|
|
|
$
|
665
|
|
Distributions to Series A preferred unitholders
|
—
|
|
|
(36
|
)
|
|
(112
|
)
|
|
(105
|
)
|
||||
Distributions to Series B preferred unitholders
|
(12
|
)
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
||||
Distributions to participating securities
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
||||
Other
|
—
|
|
|
(4
|
)
|
|
(1
|
)
|
|
(11
|
)
|
||||
Net income/(loss) allocated to common unitholders
(1)
|
$
|
697
|
|
|
$
|
(8
|
)
|
|
$
|
947
|
|
|
$
|
547
|
|
|
|
|
|
|
|
|
|
||||||||
Basic weighted average common units outstanding
|
726
|
|
|
725
|
|
|
726
|
|
|
714
|
|
||||
Effect of dilutive securities:
|
|
|
|
|
|
|
|
||||||||
Series A preferred units
|
71
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Equity-indexed compensation plan awards
|
2
|
|
|
—
|
|
|
2
|
|
|
1
|
|
||||
Diluted weighted average common units outstanding
|
799
|
|
|
725
|
|
|
728
|
|
|
715
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Diluted net income/(loss) per common unit
|
$
|
0.87
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.30
|
|
|
$
|
0.76
|
|
|
(1)
|
We calculate net income/(loss) 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.
|
|
September 30, 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
|
7,020
|
|
|
barrels
|
|
$
|
389
|
|
|
$
|
55.41
|
|
|
|
7,800
|
|
|
barrels
|
|
$
|
402
|
|
|
$
|
51.54
|
|
NGL
|
15,122
|
|
|
barrels
|
|
422
|
|
|
$
|
27.91
|
|
|
|
10,774
|
|
|
barrels
|
|
294
|
|
|
$
|
27.29
|
|
||
Other
|
N/A
|
|
|
|
|
13
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
17
|
|
|
N/A
|
|
||||
Inventory subtotal
|
|
|
|
|
|
824
|
|
|
|
|
|
|
|
|
|
|
|
713
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Linefill and base gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil
|
13,033
|
|
|
barrels
|
|
756
|
|
|
$
|
58.01
|
|
|
|
12,340
|
|
|
barrels
|
|
719
|
|
|
$
|
58.27
|
|
||
NGL
|
1,764
|
|
|
barrels
|
|
50
|
|
|
$
|
28.34
|
|
|
|
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
|
|
|
|
|
|
914
|
|
|
|
|
|
|
|
|
|
|
|
872
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil
|
1,882
|
|
|
barrels
|
|
112
|
|
|
$
|
59.51
|
|
|
|
1,870
|
|
|
barrels
|
|
105
|
|
|
$
|
56.15
|
|
||
NGL
|
2,351
|
|
|
barrels
|
|
67
|
|
|
$
|
28.50
|
|
|
|
2,167
|
|
|
barrels
|
|
59
|
|
|
$
|
27.23
|
|
||
Long-term inventory subtotal
|
|
|
|
|
|
179
|
|
|
|
|
|
|
|
|
|
|
|
164
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total
|
|
|
|
|
|
$
|
1,917
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,749
|
|
|
|
|
|
(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, 2017
|
$
|
1,070
|
|
|
$
|
988
|
|
|
$
|
508
|
|
|
$
|
2,566
|
|
Foreign currency translation adjustments
|
(8
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(13
|
)
|
||||
Dispositions
|
(10
|
)
|
|
(3
|
)
|
|
—
|
|
|
(13
|
)
|
||||
Balance at September 30, 2018
|
$
|
1,052
|
|
|
$
|
982
|
|
|
$
|
506
|
|
|
$
|
2,540
|
|
|
September 30,
2018 |
|
December 31,
2017 |
||||
SHORT-TERM DEBT
|
|
|
|
|
|
||
Commercial paper notes, bearing a weighted-average interest rate of 3.3%
(1)
|
$
|
60
|
|
|
$
|
—
|
|
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 3.2% and 2.6%, respectively
(1)
|
300
|
|
|
664
|
|
||
Other
|
69
|
|
|
73
|
|
||
Total short-term debt
(2)
|
429
|
|
|
737
|
|
||
|
|
|
|
||||
LONG-TERM DEBT
|
|
|
|
||||
Senior notes, net of unamortized discounts and debt issuance costs of $61 and $67, respectively
|
8,939
|
|
|
8,933
|
|
||
Commercial paper notes and senior secured hedged inventory facility borrowings
(3)
|
—
|
|
|
247
|
|
||
GO Zone term loans, net of debt issuance costs of $2, bearing a weighted-average interest rate of 2.9%
|
198
|
|
|
—
|
|
||
Other
|
3
|
|
|
3
|
|
||
Total long-term debt
|
9,140
|
|
|
9,183
|
|
||
Total debt
(4)
|
$
|
9,569
|
|
|
$
|
9,920
|
|
|
(1)
|
We classified these commercial paper notes and credit facility borrowings as short-term as of
September 30, 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
September 30, 2018
and
December 31, 2017
, balance includes borrowings for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.
|
(3)
|
As of
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
September 30, 2018
and
December 31, 2017
. We estimated the aggregate fair value of these notes as of
September 30, 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.
|
|
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
|
|
|
—
|
|
|
—
|
|
Other
|
—
|
|
|
—
|
|
|
899,251
|
|
Outstanding at September 30, 2018
|
71,090,468
|
|
|
800,000
|
|
|
726,088,389
|
|
|
Limited Partners
|
||||
|
Series A
Preferred Units
|
|
Common Units
|
||
Outstanding at December 31, 2016
|
64,388,853
|
|
|
669,194,419
|
|
Issuances of Series A preferred units in connection with in-kind distributions
|
3,941,096
|
|
|
—
|
|
Sales of common units
|
—
|
|
|
54,119,893
|
|
Issuance of common units in connection with acquisition of interest in Advantage Joint Venture
|
—
|
|
|
1,252,269
|
|
Other
|
—
|
|
|
622,557
|
|
Outstanding at September 30, 2017
|
68,329,949
|
|
|
725,189,138
|
|
|
|
Series A Preferred Unitholders
|
||||||||||
|
|
Distribution
(2)
|
|
|
Distribution per Unit
|
|||||||
Distribution Payment Date
|
|
Cash
|
|
Units
|
|
|
||||||
November 14, 2018
(1)
|
|
$
|
37
|
|
|
—
|
|
|
|
$
|
0.525
|
|
August 14, 2018
|
|
$
|
37
|
|
|
—
|
|
|
|
$
|
0.525
|
|
May 15, 2018
|
|
$
|
37
|
|
|
—
|
|
|
|
$
|
0.525
|
|
February 14, 2018
|
|
$
|
—
|
|
|
1,393,926
|
|
|
|
$
|
0.525
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
October 31, 2018
for the period from
July 1, 2018
through
September 30, 2018
. At
September 30, 2018
, such amount was accrued to distributions payable in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.
|
(2)
|
On February 14, 2018, we issued additional Series A preferred units in lieu of a cash distribution of
$37 million
. With respect to quarters ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we elected to pay distributions on our Series A preferred units in additional Series A preferred units. The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to quarters ending after the Initial Distribution Period, distributions on our Series A preferred units are paid in cash.
|
|
|
Series B Preferred Unitholders
|
|||||||
Distribution Payment Date
|
|
Cash Distribution
|
|
|
Distribution per Unit
|
||||
November 15, 2018
(1)
|
|
$
|
24.5
|
|
|
|
$
|
30.625
|
|
May 15, 2018
|
|
$
|
24.5
|
|
|
|
$
|
30.625
|
|
|
(1)
|
Payable to unitholders of record at the close of business on November 1, 2018 for the period from May 15, 2018 through November 14, 2018.
|
|
|
Distributions
|
|
|
Cash Distribution per Common Unit
|
||||||||||||
|
|
Common Unitholders
|
|
Total Cash Distribution
|
|
|
|||||||||||
Distribution Payment Date
|
|
Public
|
|
AAP
|
|
|
|
||||||||||
November 14, 2018
(1)
|
|
$
|
134
|
|
|
$
|
84
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
August 14, 2018
|
|
$
|
133
|
|
|
$
|
85
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
May 15, 2018
|
|
$
|
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
October 31, 2018
for the period from
July 1, 2018
through
September 30, 2018
.
|
•
|
A net long position of
5.8 million
barrels associated with our crude oil purchases, which was unwound ratably during
October 2018
to match monthly average pricing.
|
•
|
A net short time spread position of
15.4 million
barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through
December 2019
.
|
•
|
A crude oil grade basis position of
68.6 million
barrels through
December 2020
. These derivatives allow us to lock in grade basis differentials.
|
•
|
A net short position of
16.5 million
barrels through
February 2020
related to anticipated net sales of our crude oil and NGL inventory.
|
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:
|
|
|
|
|
|
|
|
|
|
|
||
|
|
2018
|
|
$
|
174
|
|
|
$
|
227
|
|
|
$1.00 - $1.30
|
|
|
|
|
|
|
|
|
|
||||
Forward exchange contracts that exchange USD for CAD:
|
|
|
|
|
|
|
|
|
|
|
||
|
|
2018
|
|
$
|
418
|
|
|
$
|
543
|
|
|
$1.00 - $1.30
|
|
|
2019
|
|
$
|
120
|
|
|
$
|
155
|
|
|
$1.00 - $1.30
|
|
|
Three Months Ended September 30, 2018
|
|
|
Three Months Ended September 30, 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
|
|
$
|
—
|
|
|
$
|
(59
|
)
|
|
$
|
(59
|
)
|
|
|
$
|
—
|
|
|
$
|
(226
|
)
|
|
$
|
(226
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Field operating costs
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense, net
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Supply and Logistics segment revenues
|
|
—
|
|
|
5
|
|
|
5
|
|
|
|
—
|
|
|
3
|
|
|
3
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other income/(expense), net
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
|
—
|
|
|
2
|
|
|
2
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(2
|
)
|
|
$
|
(57
|
)
|
|
$
|
(59
|
)
|
|
|
$
|
(10
|
)
|
|
$
|
(225
|
)
|
|
$
|
(235
|
)
|
|
|
Nine Months Ended September 30, 2018
|
|
|
Nine Months Ended September 30, 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
|
|
$
|
—
|
|
|
$
|
(443
|
)
|
|
$
|
(443
|
)
|
|
|
$
|
—
|
|
|
$
|
(31
|
)
|
|
$
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Field operating costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation and amortization
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense, net
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
|
(16
|
)
|
|
—
|
|
|
(16
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Supply and Logistics segment revenues
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other income/(expense), net
|
|
—
|
|
|
3
|
|
|
3
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(3
|
)
|
|
$
|
(447
|
)
|
|
$
|
(450
|
)
|
|
|
$
|
(19
|
)
|
|
$
|
(34
|
)
|
|
$
|
(53
|
)
|
|
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
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
Other long-term assets, net
|
|
3
|
|
|
|
|
|
|
|
||
Total derivatives designated as hedging instruments
|
|
|
$
|
15
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
||
Commodity derivatives
|
Other current assets
|
|
$
|
146
|
|
|
|
Other current assets
|
|
$
|
(358
|
)
|
|
Other long-term assets, net
|
|
54
|
|
|
|
Other long-term assets, net
|
|
(2
|
)
|
||
|
Other current liabilities
|
|
60
|
|
|
|
Other current liabilities
|
|
(211
|
)
|
||
|
Other long-term liabilities and deferred credits
|
|
9
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(39
|
)
|
||
|
|
|
|
|
|
|
|
|
||||
Foreign currency derivatives
|
Other current assets
|
|
4
|
|
|
|
Other current assets
|
|
(1
|
)
|
||
|
|
|
|
|
|
Other current liabilities
|
|
(1
|
)
|
|||
|
|
|
|
|
|
|
|
|
||||
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(19
|
)
|
||
Total derivatives not designated as hedging instruments
|
|
|
$
|
273
|
|
|
|
|
|
$
|
(631
|
)
|
|
|
|
|
|
|
|
|
|
||||
Total derivatives
|
|
|
$
|
288
|
|
|
|
|
|
$
|
(631
|
)
|
|
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
|
)
|
|
September 30,
2018 |
|
December 31,
2017 |
||||
Initial margin
|
$
|
139
|
|
|
$
|
48
|
|
Variation margin posted
|
222
|
|
|
164
|
|
||
Letters of credit
|
(102
|
)
|
|
—
|
|
||
Net broker receivable
|
$
|
259
|
|
|
$
|
212
|
|
|
September 30, 2018
|
|
|
December 31, 2017
|
||||||||||||
|
Derivative
Asset Positions |
|
Derivative
Liability Positions |
|
|
Derivative
Asset Positions |
|
Derivative
Liability Positions |
||||||||
Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Gross position - asset/(liability)
|
$
|
288
|
|
|
$
|
(631
|
)
|
|
|
$
|
90
|
|
|
$
|
(425
|
)
|
Netting adjustment
|
(430
|
)
|
|
430
|
|
|
|
(239
|
)
|
|
239
|
|
||||
Cash collateral paid
|
259
|
|
|
—
|
|
|
|
212
|
|
|
—
|
|
||||
Net position - asset/(liability)
|
$
|
117
|
|
|
$
|
(201
|
)
|
|
|
$
|
63
|
|
|
$
|
(186
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Balance Sheet Location After Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets
|
$
|
62
|
|
|
$
|
—
|
|
|
|
$
|
62
|
|
|
$
|
—
|
|
Other long-term assets, net
|
55
|
|
|
—
|
|
|
|
1
|
|
|
—
|
|
||||
Other current liabilities
|
—
|
|
|
(152
|
)
|
|
|
—
|
|
|
(151
|
)
|
||||
Other long-term liabilities and deferred credits
|
—
|
|
|
(49
|
)
|
|
|
—
|
|
|
(35
|
)
|
||||
|
$
|
117
|
|
|
$
|
(201
|
)
|
|
|
$
|
63
|
|
|
$
|
(186
|
)
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Interest rate derivatives, net
|
$
|
15
|
|
|
$
|
(3
|
)
|
|
$
|
60
|
|
|
$
|
(15
|
)
|
|
|
Fair Value as of September 30, 2018
|
|
|
Fair Value as of December 31, 2017
|
||||||||||||||||||||||||||||
Recurring Fair Value Measures
(1)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
Commodity derivatives
|
|
$
|
(11
|
)
|
|
$
|
(326
|
)
|
|
$
|
(4
|
)
|
|
$
|
(341
|
)
|
|
|
$
|
5
|
|
|
$
|
(278
|
)
|
|
$
|
(8
|
)
|
|
$
|
(281
|
)
|
Interest rate derivatives
|
|
—
|
|
|
15
|
|
|
—
|
|
|
15
|
|
|
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(36
|
)
|
||||||||
Foreign currency derivatives
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
||||||||
Preferred Distribution Rate Reset Option
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
||||||||
Total net derivative asset/(liability)
|
|
$
|
(11
|
)
|
|
$
|
(309
|
)
|
|
$
|
(23
|
)
|
|
$
|
(343
|
)
|
|
|
$
|
5
|
|
|
$
|
(310
|
)
|
|
$
|
(30
|
)
|
|
$
|
(335
|
)
|
|
(1)
|
Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Beginning Balance
|
$
|
(18
|
)
|
|
$
|
(30
|
)
|
|
$
|
(30
|
)
|
|
$
|
(36
|
)
|
Net gains/(losses) for the period included in earnings
|
(5
|
)
|
|
(8
|
)
|
|
2
|
|
|
(1
|
)
|
||||
Settlements
|
—
|
|
|
(1
|
)
|
|
7
|
|
|
4
|
|
||||
Derivatives entered into during the period
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
(8
|
)
|
||||
Ending Balance
|
$
|
(23
|
)
|
|
$
|
(41
|
)
|
|
$
|
(23
|
)
|
|
$
|
(41
|
)
|
|
|
|
|
|
|
|
|
||||||||
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period
|
$
|
(5
|
)
|
|
$
|
(10
|
)
|
|
$
|
—
|
|
|
$
|
(8
|
)
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Revenues
|
$
|
260
|
|
|
$
|
204
|
|
|
$
|
818
|
|
|
$
|
657
|
|
|
|
|
|
|
|
|
|
||||||||
Purchases and related costs
(1)
|
$
|
(22
|
)
|
|
$
|
(68
|
)
|
|
$
|
(184
|
)
|
|
$
|
(169
|
)
|
|
(1)
|
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.
|
|
September 30,
2018 |
|
December 31,
2017 |
||||
Trade accounts receivable and other receivables
|
$
|
1,039
|
|
|
$
|
1,075
|
|
|
|
|
|
||||
Accounts payable
|
$
|
976
|
|
|
$
|
990
|
|
Three Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Intersegment Adjustment
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
External customers
(1)
|
|
$
|
292
|
|
|
$
|
149
|
|
|
$
|
8,482
|
|
|
$
|
(131
|
)
|
|
$
|
8,792
|
|
Intersegment
(2)
|
|
206
|
|
|
140
|
|
|
1
|
|
|
131
|
|
|
478
|
|
|||||
Total revenues of reportable segments
|
|
$
|
498
|
|
|
$
|
289
|
|
|
$
|
8,483
|
|
|
$
|
—
|
|
|
$
|
9,270
|
|
Equity earnings in unconsolidated entities
|
|
$
|
110
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
110
|
|
||
Segment Adjusted EBITDA
|
|
$
|
388
|
|
|
$
|
173
|
|
|
$
|
75
|
|
|
|
|
$
|
636
|
|
||
Maintenance capital
|
|
$
|
41
|
|
|
$
|
33
|
|
|
$
|
4
|
|
|
|
|
$
|
78
|
|
Three Months Ended September 30, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Intersegment Adjustment
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
External customers
(1)
|
|
$
|
274
|
|
|
$
|
140
|
|
|
$
|
5,573
|
|
|
$
|
(114
|
)
|
|
$
|
5,873
|
|
Intersegment
(2)
|
|
172
|
|
|
151
|
|
|
1
|
|
|
114
|
|
|
438
|
|
|||||
Total revenues of reportable segments
|
|
$
|
446
|
|
|
$
|
291
|
|
|
$
|
5,574
|
|
|
$
|
—
|
|
|
$
|
6,311
|
|
Equity earnings in unconsolidated entities
|
|
$
|
80
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
80
|
|
||
Segment Adjusted EBITDA
|
|
$
|
363
|
|
|
$
|
182
|
|
|
$
|
(56
|
)
|
|
|
|
$
|
489
|
|
||
Maintenance capital
|
|
$
|
32
|
|
|
$
|
28
|
|
|
$
|
3
|
|
|
|
|
$
|
63
|
|
Nine Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Intersegment Adjustment
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
External customers
(1)
|
|
$
|
808
|
|
|
$
|
437
|
|
|
$
|
24,374
|
|
|
$
|
(350
|
)
|
|
$
|
25,269
|
|
Intersegment
(2)
|
|
619
|
|
|
429
|
|
|
2
|
|
|
350
|
|
|
1,400
|
|
|||||
Total revenues of reportable segments
|
|
$
|
1,427
|
|
|
$
|
866
|
|
|
$
|
24,376
|
|
|
$
|
—
|
|
|
$
|
26,669
|
|
Equity earnings in unconsolidated entities
|
|
$
|
281
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
281
|
|
||
Segment Adjusted EBITDA
|
|
$
|
1,083
|
|
|
$
|
530
|
|
|
$
|
120
|
|
|
|
|
$
|
1,733
|
|
||
Maintenance capital
|
|
$
|
102
|
|
|
$
|
74
|
|
|
$
|
10
|
|
|
|
|
$
|
186
|
|
Nine Months Ended September 30, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics |
|
Intersegment Adjustment
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
External customers
(1)
|
|
$
|
757
|
|
|
$
|
410
|
|
|
$
|
17,749
|
|
|
$
|
(298
|
)
|
|
$
|
18,618
|
|
Intersegment
(2)
|
|
503
|
|
|
463
|
|
|
8
|
|
|
298
|
|
|
1,272
|
|
|||||
Total revenues of reportable segments
|
|
$
|
1,260
|
|
|
$
|
873
|
|
|
$
|
17,757
|
|
|
$
|
—
|
|
|
$
|
19,890
|
|
Equity earnings in unconsolidated entities
|
|
$
|
201
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
201
|
|
||
Segment Adjusted EBITDA
|
|
$
|
933
|
|
|
$
|
550
|
|
|
$
|
(32
|
)
|
|
|
|
$
|
1,451
|
|
||
Maintenance capital
|
|
$
|
89
|
|
|
$
|
94
|
|
|
$
|
11
|
|
|
|
|
$
|
194
|
|
|
(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
for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue from external customers presented above and adjusted those revenues out such that Total revenue 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
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Segment Adjusted EBITDA
|
$
|
636
|
|
|
$
|
489
|
|
|
$
|
1,733
|
|
|
$
|
1,451
|
|
Adjustments
(1)
:
|
|
|
|
|
|
|
|
||||||||
Depreciation and amortization of unconsolidated entities
(2)
|
(15
|
)
|
|
(13
|
)
|
|
(44
|
)
|
|
(31
|
)
|
||||
Gains/(losses) from derivative activities net of inventory valuation adjustments
(3)
|
110
|
|
|
(216
|
)
|
|
(107
|
)
|
|
86
|
|
||||
Long-term inventory costing adjustments
(4)
|
10
|
|
|
16
|
|
|
18
|
|
|
2
|
|
||||
Deficiencies under minimum volume commitments, net
(5)
|
4
|
|
|
(8
|
)
|
|
(9
|
)
|
|
(5
|
)
|
||||
Equity-indexed compensation expense
(6)
|
(14
|
)
|
|
(7
|
)
|
|
(37
|
)
|
|
(18
|
)
|
||||
Net gain/(loss) on foreign currency revaluation
(7)
|
3
|
|
|
14
|
|
|
(5
|
)
|
|
27
|
|
||||
Line 901 incident
(8)
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
||||
Significant acquisition-related expenses
(9)
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
||||
Depreciation and amortization
|
(131
|
)
|
|
(151
|
)
|
|
(306
|
)
|
|
(401
|
)
|
||||
Gain on sale of investment in unconsolidated entities
|
210
|
|
|
—
|
|
|
210
|
|
|
—
|
|
||||
Interest expense, net
|
(110
|
)
|
|
(134
|
)
|
|
(327
|
)
|
|
(390
|
)
|
||||
Other income/(expense), net
|
(3
|
)
|
|
(1
|
)
|
|
8
|
|
|
(6
|
)
|
||||
Income/(loss) before tax
|
700
|
|
|
(11
|
)
|
|
1,134
|
|
|
697
|
|
||||
Income tax (expense)/benefit
|
10
|
|
|
45
|
|
|
(35
|
)
|
|
(30
|
)
|
||||
Net income
|
710
|
|
|
34
|
|
|
1,099
|
|
|
667
|
|
||||
Net income attributable to noncontrolling interests
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(2
|
)
|
||||
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
$
|
1,099
|
|
|
$
|
665
|
|
|
(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 from the revaluation of foreign currency transactions and monetary assets and liabilities.
|
(8)
|
Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See
Note 13
for additional information regarding the Line 901 incident.
|
(9)
|
Includes acquisition-related expenses associated with the acquisition of the Alpha Crude Connector Gathering System (the “ACC Acquisition”). See Note 6 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for additional discussion.
|
Item 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Executive Summary
|
•
|
Acquisitions and 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
|
•
|
More 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;
|
•
|
Favorable regional crude oil differentials and higher lease gathering and NGL margins in our Supply and Logistics segment;
|
•
|
Lower depreciation and amortization expense due to net gains recognized during the
2018
period associated with asset sales;
|
•
|
A gain on the sale of a portion of our interest in BridgeTex in the third quarter of 2018; and
|
•
|
Lower interest expense primarily driven by a lower weighted average debt balance in the 2018 period as a result of our efforts to implement our Leverage Reduction Plan announced in August 2017. See “—
Executive Summary
—
Overview of Operating Results, Capital Investments and Other Significant Activities
” in Item 7 of our
2017
Annual Report on Form 10-K for further discussion of our Leverage Reduction Plan; partially offset by
|
•
|
The negative impact, primarily in our Supply and Logistics segment, associated with the difference between losses recognized in the 2018 period from the mark-to-market of certain derivative instruments, as compared to gains recognized in the prior period; and
|
•
|
Lower operating results due to asset sales completed during 2017 and 2018 as part of our divestiture program.
|
|
Nine Months Ended
September 30, |
||||||
|
2018
|
|
2017
|
||||
Acquisition capital
(1) (2)
|
$
|
—
|
|
|
$
|
1,325
|
|
Expansion capital
(2) (3)
|
1,370
|
|
|
893
|
|
||
Maintenance capital
(3)
|
186
|
|
|
194
|
|
||
|
$
|
1,556
|
|
|
$
|
2,412
|
|
|
(1)
|
Acquisition capital for the first nine months of 2017 primarily relates to the ACC Acquisition.
|
(2)
|
Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.” Subsequent 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.
|
(3)
|
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
|
|
2018
|
||
Permian Basin Takeaway Pipeline Projects
|
|
$
|
925
|
|
Complementary Permian Basin Projects
|
|
675
|
|
|
Selected Facilities Projects
(1)
|
|
65
|
|
|
Other Projects
|
|
285
|
|
|
Total Projected 2018 Expansion Capital Expenditures
|
|
$
|
1,950
|
|
|
(1)
|
Includes projects at our St. James, Fort Saskatchewan and Cushing terminals.
|
|
Three Months Ended
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||||||||
|
2018
|
|
2017
|
|
$
|
|
%
|
|
|
2018
|
|
2017
|
|
$
|
|
%
|
||||||||||||||
Transportation Segment Adjusted EBITDA
(1)
|
$
|
388
|
|
|
$
|
363
|
|
|
$
|
25
|
|
|
7
|
%
|
|
|
$
|
1,083
|
|
|
$
|
933
|
|
|
$
|
150
|
|
|
16
|
%
|
Facilities Segment Adjusted EBITDA
(1)
|
173
|
|
|
182
|
|
|
(9
|
)
|
|
(5
|
)%
|
|
|
530
|
|
|
550
|
|
|
(20
|
)
|
|
(4
|
)%
|
||||||
Supply and Logistics Segment Adjusted EBITDA
(1)
|
75
|
|
|
(56
|
)
|
|
131
|
|
|
234
|
%
|
|
|
120
|
|
|
(32
|
)
|
|
152
|
|
|
475
|
%
|
||||||
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Depreciation and amortization of unconsolidated entities
|
(15
|
)
|
|
(13
|
)
|
|
(2
|
)
|
|
(15
|
)%
|
|
|
(44
|
)
|
|
(31
|
)
|
|
(13
|
)
|
|
(42
|
)%
|
||||||
Selected items impacting comparability - Segment Adjusted EBITDA
|
113
|
|
|
(201
|
)
|
|
314
|
|
|
**
|
|
|
|
(140
|
)
|
|
74
|
|
|
(214
|
)
|
|
**
|
|
||||||
Depreciation and amortization
|
(131
|
)
|
|
(151
|
)
|
|
20
|
|
|
13
|
%
|
|
|
(306
|
)
|
|
(401
|
)
|
|
95
|
|
|
24
|
%
|
||||||
Gain on sale of investment in unconsolidated entities
|
210
|
|
|
—
|
|
|
210
|
|
|
N/A
|
|
|
|
210
|
|
|
—
|
|
|
210
|
|
|
N/A
|
|
||||||
Interest expense, net
|
(110
|
)
|
|
(134
|
)
|
|
24
|
|
|
18
|
%
|
|
|
(327
|
)
|
|
(390
|
)
|
|
63
|
|
|
16
|
%
|
||||||
Other income/(expense), net
|
(3
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
**
|
|
|
|
8
|
|
|
(6
|
)
|
|
14
|
|
|
**
|
|
||||||
Income tax (expense)/benefit
|
10
|
|
|
45
|
|
|
(35
|
)
|
|
(78
|
)%
|
|
|
(35
|
)
|
|
(30
|
)
|
|
(5
|
)
|
|
(17
|
)%
|
||||||
Net income
|
$
|
710
|
|
|
$
|
34
|
|
|
$
|
676
|
|
|
**
|
|
|
|
$
|
1,099
|
|
|
$
|
667
|
|
|
$
|
432
|
|
|
65
|
%
|
Net income attributable to noncontrolling interests
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
100
|
%
|
|
|
—
|
|
|
(2
|
)
|
|
2
|
|
|
100
|
%
|
||||||
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
$
|
677
|
|
|
**
|
|
|
|
$
|
1,099
|
|
|
$
|
665
|
|
|
$
|
434
|
|
|
65
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Basic net income/(loss) per common unit
|
$
|
0.91
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.92
|
|
|
**
|
|
|
|
$
|
1.30
|
|
|
$
|
0.77
|
|
|
$
|
0.53
|
|
|
**
|
|
Diluted net income/(loss) per common unit
|
$
|
0.87
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.88
|
|
|
**
|
|
|
|
$
|
1.30
|
|
|
$
|
0.76
|
|
|
$
|
0.54
|
|
|
**
|
|
Basic weighted average common units outstanding
|
726
|
|
|
725
|
|
|
1
|
|
|
**
|
|
|
|
726
|
|
|
714
|
|
|
12
|
|
|
**
|
|
||||||
Diluted weighted average common units outstanding
|
799
|
|
|
725
|
|
|
74
|
|
|
**
|
|
|
|
728
|
|
|
715
|
|
|
13
|
|
|
**
|
|
|
**
|
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
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||||||||
|
2018
|
|
2017
|
|
$
|
|
%
|
|
|
2018
|
|
2017
|
|
$
|
|
%
|
||||||||||||||
Net income
|
$
|
710
|
|
|
$
|
34
|
|
|
$
|
676
|
|
|
**
|
|
|
|
$
|
1,099
|
|
|
$
|
667
|
|
|
$
|
432
|
|
|
65
|
%
|
Add/(Subtract):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
110
|
|
|
134
|
|
|
(24
|
)
|
|
(18
|
)%
|
|
|
327
|
|
|
390
|
|
|
(63
|
)
|
|
(16
|
)%
|
||||||
Income tax expense/(benefit)
|
(10
|
)
|
|
(45
|
)
|
|
35
|
|
|
78
|
%
|
|
|
35
|
|
|
30
|
|
|
5
|
|
|
17
|
%
|
||||||
Depreciation and amortization
|
131
|
|
|
151
|
|
|
(20
|
)
|
|
(13
|
)%
|
|
|
306
|
|
|
401
|
|
|
(95
|
)
|
|
(24
|
)%
|
||||||
Depreciation and amortization of unconsolidated entities
(1)
|
15
|
|
|
13
|
|
|
2
|
|
|
15
|
%
|
|
|
44
|
|
|
31
|
|
|
13
|
|
|
42
|
%
|
||||||
Gain on sale of investment in unconsolidated entities
|
(210
|
)
|
|
—
|
|
|
(210
|
)
|
|
N/A
|
|
|
|
(210
|
)
|
|
—
|
|
|
(210
|
)
|
|
N/A
|
|
||||||
Selected Items Impacting Comparability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Gains)/losses from derivative activities net of inventory valuation adjustments
(2)
|
(110
|
)
|
|
216
|
|
|
(326
|
)
|
|
**
|
|
|
|
107
|
|
|
(86
|
)
|
|
193
|
|
|
**
|
|
||||||
Long-term inventory costing adjustments
(3)
|
(10
|
)
|
|
(16
|
)
|
|
6
|
|
|
**
|
|
|
|
(18
|
)
|
|
(2
|
)
|
|
(16
|
)
|
|
**
|
|
||||||
Deficiencies under minimum volume commitments, net
(4)
|
(4
|
)
|
|
8
|
|
|
(12
|
)
|
|
**
|
|
|
|
9
|
|
|
5
|
|
|
4
|
|
|
**
|
|
||||||
Equity-indexed compensation expense
(5)
|
14
|
|
|
7
|
|
|
7
|
|
|
**
|
|
|
|
37
|
|
|
18
|
|
|
19
|
|
|
**
|
|
||||||
Net (gain)/loss on foreign currency revaluation
(6)
|
(3
|
)
|
|
(14
|
)
|
|
11
|
|
|
**
|
|
|
|
5
|
|
|
(27
|
)
|
|
32
|
|
|
**
|
|
||||||
Line 901 incident
(7)
|
—
|
|
|
—
|
|
|
—
|
|
|
**
|
|
|
|
—
|
|
|
12
|
|
|
(12
|
)
|
|
**
|
|
||||||
Significant acquisition-related expenses
(8)
|
—
|
|
|
—
|
|
|
—
|
|
|
**
|
|
|
|
—
|
|
|
6
|
|
|
(6
|
)
|
|
**
|
|
||||||
Selected Items Impacting Comparability - Segment Adjusted EBITDA
|
(113
|
)
|
|
201
|
|
|
(314
|
)
|
|
**
|
|
|
|
140
|
|
|
(74
|
)
|
|
214
|
|
|
**
|
|
||||||
(Gains)/losses from derivative activities
(2)
|
2
|
|
|
(2
|
)
|
|
4
|
|
|
**
|
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
**
|
|
||||||
Net (gain)/loss on foreign currency revaluation
(6)
|
1
|
|
|
3
|
|
|
(2
|
)
|
|
**
|
|
|
|
(3
|
)
|
|
7
|
|
|
(10
|
)
|
|
**
|
|
||||||
Selected Items Impacting Comparability - Adjusted
EBITDA (9) |
(110
|
)
|
|
202
|
|
|
(312
|
)
|
|
**
|
|
|
|
134
|
|
|
(67
|
)
|
|
201
|
|
|
**
|
|
||||||
Adjusted EBITDA
(9)
|
$
|
636
|
|
|
$
|
489
|
|
|
$
|
147
|
|
|
30
|
%
|
|
|
$
|
1,735
|
|
|
$
|
1,452
|
|
|
$
|
283
|
|
|
19
|
%
|
Interest expense, net
(10)
|
(106
|
)
|
|
(121
|
)
|
|
15
|
|
|
12
|
%
|
|
|
(318
|
)
|
|
(367
|
)
|
|
49
|
|
|
13
|
%
|
||||||
Maintenance capital
(11)
|
(78
|
)
|
|
(63
|
)
|
|
(15
|
)
|
|
(24
|
)%
|
|
|
(186
|
)
|
|
(194
|
)
|
|
8
|
|
|
4
|
%
|
||||||
Current income tax (expense)/benefit
|
(14
|
)
|
|
1
|
|
|
(15
|
)
|
|
**
|
|
|
|
(34
|
)
|
|
(9
|
)
|
|
(25
|
)
|
|
(278
|
)%
|
||||||
Adjusted equity earnings in unconsolidated entities, net of distributions
(12)
|
(5
|
)
|
|
(7
|
)
|
|
2
|
|
|
**
|
|
|
|
9
|
|
|
11
|
|
|
(2
|
)
|
|
**
|
|
||||||
Distributions to noncontrolling interests
(13)
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
100
|
%
|
|
|
—
|
|
|
(2
|
)
|
|
2
|
|
|
100
|
%
|
||||||
Implied DCF
(14)
|
$
|
433
|
|
|
$
|
298
|
|
|
135
|
|
|
45
|
%
|
|
|
$
|
1,206
|
|
|
$
|
891
|
|
|
315
|
|
|
35
|
%
|
||
Preferred unit distributions
(15)
|
(37
|
)
|
|
—
|
|
|
(37
|
)
|
|
N/A
|
|
|
|
(99
|
)
|
|
—
|
|
|
(99
|
)
|
|
N/A
|
|
||||||
Implied DCF Available to Common Unitholders
|
$
|
396
|
|
|
$
|
298
|
|
|
$
|
98
|
|
|
33
|
%
|
|
|
$
|
1,107
|
|
|
$
|
891
|
|
|
$
|
216
|
|
|
24
|
%
|
Common unit cash distributions
(13)
|
(218
|
)
|
|
(399
|
)
|
|
|
|
|
|
|
(653
|
)
|
|
(1,168
|
)
|
|
|
|
|
||||||||||
Implied DCF Excess/(Shortage)
(16)
|
$
|
178
|
|
|
$
|
(101
|
)
|
|
|
|
|
|
|
$
|
454
|
|
|
$
|
(277
|
)
|
|
|
|
|
|
**
|
Indicates that variance as a percentage is not meaningful.
|
(1)
|
Over the past several years, we have increased our participation in pipeline strategic 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 of 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 11
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 4 to our Consolidated Financial Statements included in Part IV of our
2017
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 16 to our Consolidated Financial Statements included in Part IV of our
2017
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 11
to our Condensed Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities.
|
(7)
|
Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional information regarding the Line 901 incident.
|
(8)
|
Includes acquisition-related expenses associated with the ACC Acquisition in February 2017.
|
(9)
|
Adjusted EBITDA includes Other income/(expense), net adjusted for selected items impacting comparability (“Adjusted Other income/(expense), net”). Segment Adjusted EBITDA does not include Adjusted Other income/(expense), net.
|
(10)
|
Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.
|
(11)
|
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.
|
(12)
|
Represents the difference between non-cash equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains and losses on significant asset sales) and cash distributions received from such entities.
|
(13)
|
Cash distributions paid during the period presented.
|
(14)
|
Including net costs recognized during the period related to the Line 901 incident that occurred in May 2015, Implied DCF would have been $879 million for the nine months ended September 30, 2017. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional information regarding the Line 901 incident.
|
(15)
|
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 11 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for additional information regarding our preferred units.
|
(16)
|
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
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||||||||
(in millions, except per barrel data)
|
|
2018
|
|
2017
|
|
$
|
|
%
|
|
|
2018
|
|
2017
|
|
$
|
|
%
|
||||||||||||||
Revenues
|
|
$
|
498
|
|
|
$
|
446
|
|
|
$
|
52
|
|
|
12
|
%
|
|
|
$
|
1,427
|
|
|
$
|
1,260
|
|
|
$
|
167
|
|
|
13
|
%
|
Purchases and related costs
|
|
(49
|
)
|
|
(29
|
)
|
|
(20
|
)
|
|
(69
|
)%
|
|
|
(141
|
)
|
|
(74
|
)
|
|
(67
|
)
|
|
(91
|
)%
|
||||||
Field operating costs
|
|
(164
|
)
|
|
(136
|
)
|
|
(28
|
)
|
|
(21
|
)%
|
|
|
(469
|
)
|
|
(436
|
)
|
|
(33
|
)
|
|
(8
|
)%
|
||||||
Segment general and administrative expenses
(2)
|
|
(28
|
)
|
|
(25
|
)
|
|
(3
|
)
|
|
(12
|
)%
|
|
|
(86
|
)
|
|
(78
|
)
|
|
(8
|
)
|
|
(10
|
)%
|
||||||
Equity earnings in unconsolidated entities
|
|
110
|
|
|
80
|
|
|
30
|
|
|
38
|
%
|
|
|
281
|
|
|
201
|
|
|
80
|
|
|
40
|
%
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Adjustments
(3)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Depreciation and amortization of unconsolidated entities
|
|
15
|
|
|
13
|
|
|
2
|
|
|
15
|
%
|
|
|
44
|
|
|
31
|
|
|
13
|
|
|
42
|
%
|
||||||
Gains from derivative activities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
**
|
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
**
|
|
||||||
Deficiencies under minimum volume commitments, net
|
|
(1
|
)
|
|
11
|
|
|
(12
|
)
|
|
**
|
|
|
|
8
|
|
|
2
|
|
|
6
|
|
|
**
|
|
||||||
Equity-indexed compensation expense
|
|
7
|
|
|
3
|
|
|
4
|
|
|
**
|
|
|
|
20
|
|
|
9
|
|
|
11
|
|
|
**
|
|
||||||
Line 901 incident
|
|
—
|
|
|
—
|
|
|
—
|
|
|
**
|
|
|
|
—
|
|
|
12
|
|
|
(12
|
)
|
|
**
|
|
||||||
Significant acquisition-related expenses
|
|
—
|
|
|
—
|
|
|
—
|
|
|
**
|
|
|
|
—
|
|
|
6
|
|
|
(6
|
)
|
|
**
|
|
||||||
Segment Adjusted EBITDA
|
|
$
|
388
|
|
|
$
|
363
|
|
|
$
|
25
|
|
|
7
|
%
|
|
|
$
|
1,083
|
|
|
$
|
933
|
|
|
$
|
150
|
|
|
16
|
%
|
Maintenance capital
|
|
$
|
41
|
|
|
$
|
32
|
|
|
$
|
9
|
|
|
28
|
%
|
|
|
$
|
102
|
|
|
$
|
89
|
|
|
$
|
13
|
|
|
15
|
%
|
Segment Adjusted EBITDA per barrel
|
|
$
|
0.70
|
|
|
$
|
0.74
|
|
|
$
|
(0.04
|
)
|
|
(5
|
)%
|
|
|
$
|
0.69
|
|
|
$
|
0.67
|
|
|
$
|
0.02
|
|
|
3
|
%
|
Average Daily Volumes
|
|
Three Months Ended
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||
(in thousands of barrels per day)
(4)
|
|
2018
|
|
2017
|
|
Volumes
|
|
%
|
|
|
2018
|
|
2017
|
|
Volumes
|
|
%
|
||||||||
Tariff activities volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil pipelines (by region):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Permian Basin
(5)
|
|
3,880
|
|
|
2,963
|
|
|
917
|
|
|
31
|
%
|
|
|
3,621
|
|
|
2,732
|
|
|
889
|
|
|
33
|
%
|
South Texas / Eagle Ford
(5)
|
|
451
|
|
|
362
|
|
|
89
|
|
|
25
|
%
|
|
|
436
|
|
|
341
|
|
|
95
|
|
|
28
|
%
|
Central
(5)
|
|
480
|
|
|
424
|
|
|
56
|
|
|
13
|
%
|
|
|
456
|
|
|
419
|
|
|
37
|
|
|
9
|
%
|
Gulf Coast
|
|
171
|
|
|
359
|
|
|
(188
|
)
|
|
(52
|
)%
|
|
|
182
|
|
|
362
|
|
|
(180
|
)
|
|
(50
|
)%
|
Rocky Mountain
(5)
|
|
258
|
|
|
426
|
|
|
(168
|
)
|
|
(39
|
)%
|
|
|
261
|
|
|
418
|
|
|
(157
|
)
|
|
(38
|
)%
|
Western
|
|
184
|
|
|
190
|
|
|
(6
|
)
|
|
(3
|
)%
|
|
|
180
|
|
|
186
|
|
|
(6
|
)
|
|
(3
|
)%
|
Canada
|
|
322
|
|
|
351
|
|
|
(29
|
)
|
|
(8
|
)%
|
|
|
312
|
|
|
359
|
|
|
(47
|
)
|
|
(13
|
)%
|
Crude oil pipelines
|
|
5,746
|
|
|
5,075
|
|
|
671
|
|
|
13
|
%
|
|
|
5,448
|
|
|
4,817
|
|
|
631
|
|
|
13
|
%
|
NGL pipelines
|
|
174
|
|
|
172
|
|
|
2
|
|
|
1
|
%
|
|
|
173
|
|
|
169
|
|
|
4
|
|
|
2
|
%
|
Tariff activities total volumes
|
|
5,920
|
|
|
5,247
|
|
|
673
|
|
|
13
|
%
|
|
|
5,621
|
|
|
4,986
|
|
|
635
|
|
|
13
|
%
|
Trucking volumes
|
|
95
|
|
|
94
|
|
|
1
|
|
|
1
|
%
|
|
|
95
|
|
|
102
|
|
|
(7
|
)
|
|
(7
|
)%
|
Transportation segment total volumes
|
|
6,015
|
|
|
5,341
|
|
|
674
|
|
|
13
|
%
|
|
|
5,716
|
|
|
5,088
|
|
|
628
|
|
|
12
|
%
|
|
**
|
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 September 30, 2018-2017 |
|
|
Favorable/(Unfavorable) Variance
Nine Months Ended September 30, 2018-2017 |
||||||||||||||||||||
(in millions)
|
|
Revenues
|
|
Purchases and
Related Costs |
|
Equity
Earnings |
|
|
Revenues
|
|
Purchases and
Related Costs |
|
Equity
Earnings |
||||||||||||
Permian Basin region
|
|
$
|
64
|
|
|
$
|
(14
|
)
|
|
$
|
14
|
|
|
|
$
|
198
|
|
|
$
|
(59
|
)
|
|
$
|
37
|
|
South Texas / Eagle Ford region
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
7
|
|
|
—
|
|
|
12
|
|
||||||
Central region
|
|
(1
|
)
|
|
—
|
|
|
16
|
|
|
|
(12
|
)
|
|
—
|
|
|
38
|
|
||||||
Gulf Coast region
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
|
(26
|
)
|
|
—
|
|
|
—
|
|
||||||
Rocky Mountain region
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
|
|
(30
|
)
|
|
—
|
|
|
—
|
|
||||||
Other regions (including trucking and pipeline loss allowance revenue)
|
|
9
|
|
|
(6
|
)
|
|
—
|
|
|
|
30
|
|
|
(8
|
)
|
|
(7
|
)
|
||||||
Total variance
|
|
$
|
52
|
|
|
$
|
(20
|
)
|
|
$
|
30
|
|
|
|
$
|
167
|
|
|
$
|
(67
|
)
|
|
$
|
80
|
|
•
|
Permian Basin region.
Total revenues, net of purchases and related costs, and equity earnings in unconsolidated entities increased by approximately $64 million and $176 million, respectively, for the three- and
nine
-month comparative periods primarily due to higher volumes from increased production and our recently completed capital expansion projects. For the
three and nine
months ended
September 30, 2018
, these increases included (i) higher volumes on our gathering systems of approximately 350,000 and 339,000 barrels per day, respectively, primarily on our Pinon and Spraberry pipelines and ACC system, (ii) higher volumes of approximately 415,000 and 381,000 barrels per day, respectively, on our intra-basin pipelines and (iii) a volume increase of approximately 152,000 and 169,000 barrels per day, respectively, on our long-haul pipelines, including our equity interest in BridgeTex.
|
•
|
South Texas / Eagle Ford region.
Revenues increased for each of the comparative periods presented due to higher receipts on certain of our gathering systems.
|
•
|
Central region.
The decrease in revenues for each of the comparative periods was primarily due to the sale of certain of our Mid-Continent Area System assets in the fourth quarter of 2017, including the sale of a portion of our interest in our Midway pipeline for which our remaining interest is now accounted for under the equity method of accounting. However, such unfavorable results were partially offset by additional movements on our Red River pipeline in the 2018 periods.
|
•
|
Gulf Coast Region.
The decrease in revenues for each of the comparative periods was primarily due to lower volumes on the Capline pipeline once the Diamond joint venture pipeline was placed in service in late 2017.
|
•
|
Rocky Mountain Region.
The decrease in revenues and volumes for each of the comparative periods was primarily due to the sale of certain pipelines and related assets in the fourth quarter of 2017 and the second quarter of 2018, partially offset by higher volumes on certain of our remaining pipelines.
|
•
|
Other.
The increase in other revenue for each of the comparative periods was primarily due to greater loss allowance revenue driven by higher volumes and prices in the 2018 periods. The decrease in volumes on our Canadian crude oil pipelines for each of the comparative periods was partially due to the temporary outage of a connecting carrier. Additionally, the impact on revenues from the decrease in volumes was partially offset by increased tariff rates on certain of the pipelines.
|
Operating Results
(1)
|
|
Three Months Ended
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||||||||
(in millions, except per barrel data)
|
|
2018
|
|
2017
|
|
$
|
|
%
|
|
|
2018
|
|
2017
|
|
$
|
|
%
|
||||||||||||||
Revenues
|
|
$
|
289
|
|
|
$
|
291
|
|
|
$
|
(2
|
)
|
|
(1
|
)%
|
|
|
$
|
866
|
|
|
$
|
873
|
|
|
$
|
(7
|
)
|
|
(1
|
)%
|
Purchases and related costs
|
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
%
|
|
|
(12
|
)
|
|
(19
|
)
|
|
7
|
|
|
37
|
%
|
||||||
Field operating costs
|
|
(95
|
)
|
|
(89
|
)
|
|
(6
|
)
|
|
(7
|
)%
|
|
|
(271
|
)
|
|
(258
|
)
|
|
(13
|
)
|
|
(5
|
)%
|
||||||
Segment general and administrative expenses
(2)
|
|
(18
|
)
|
|
(18
|
)
|
|
—
|
|
|
—
|
%
|
|
|
(59
|
)
|
|
(55
|
)
|
|
(4
|
)
|
|
(7
|
)%
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Adjustments
(3)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
(Gains)/losses from derivative activities
|
|
—
|
|
|
2
|
|
|
(2
|
)
|
|
**
|
|
|
|
(2
|
)
|
|
3
|
|
|
(5
|
)
|
|
**
|
|
||||||
Deficiencies under minimum volume commitments, net
|
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|
**
|
|
|
|
1
|
|
|
3
|
|
|
(2
|
)
|
|
**
|
|
||||||
Equity-indexed compensation expense
|
|
3
|
|
|
2
|
|
|
1
|
|
|
**
|
|
|
|
7
|
|
|
3
|
|
|
4
|
|
|
**
|
|
||||||
Segment Adjusted EBITDA
|
|
$
|
173
|
|
|
$
|
182
|
|
|
$
|
(9
|
)
|
|
(5
|
)%
|
|
|
$
|
530
|
|
|
$
|
550
|
|
|
$
|
(20
|
)
|
|
(4
|
)%
|
Maintenance capital
|
|
$
|
33
|
|
|
$
|
28
|
|
|
$
|
5
|
|
|
18
|
%
|
|
|
$
|
74
|
|
|
$
|
94
|
|
|
$
|
(20
|
)
|
|
(21
|
)%
|
Segment Adjusted EBITDA per barrel
|
|
$
|
0.47
|
|
|
$
|
0.48
|
|
|
$
|
(0.01
|
)
|
|
(2
|
)%
|
|
|
$
|
0.48
|
|
|
$
|
0.47
|
|
|
$
|
0.01
|
|
|
2
|
%
|
|
|
Three Months Ended
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||
Volumes
(4)
|
|
2018
|
|
2017
|
|
Volumes
|
|
%
|
|
|
2018
|
|
2017
|
|
Volumes
|
|
%
|
||||||||
Liquids storage (average monthly capacity in millions of barrels)
|
|
109
|
|
|
112
|
|
|
(3
|
)
|
|
(3
|
)%
|
|
|
109
|
|
|
112
|
|
|
(3
|
)
|
|
(3
|
)%
|
Natural gas storage (average monthly working capacity in billions of cubic feet)
(5)
|
|
65
|
|
|
67
|
|
|
(2
|
)
|
|
(3
|
)%
|
|
|
66
|
|
|
87
|
|
|
(21
|
)
|
|
(24
|
)%
|
NGL fractionation (average volumes in thousands of barrels per day)
|
|
115
|
|
|
131
|
|
|
(16
|
)
|
|
(12
|
)%
|
|
|
128
|
|
|
125
|
|
|
3
|
|
|
2
|
%
|
Facilities segment total volumes (average monthly volumes in millions of barrels)
(6)
|
|
123
|
|
|
127
|
|
|
(4
|
)
|
|
(3
|
)%
|
|
|
124
|
|
|
130
|
|
|
(6
|
)
|
|
(5
|
)%
|
|
**
|
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 (i) the sale of our Bluewater natural gas storage facility in June 2017, (ii) changes in base gas and (iii) 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.
|
•
|
NGL Operations.
Revenues decreased by $13 million and less than $1 million for the
three and nine
months ended
September 30, 2018
, respectively, compared to the same periods in
2017
. The three- and nine-month comparative periods were impacted by the sale of a natural gas processing facility in the second quarter of 2018 and decreases in revenues at certain of our storage and fractionation facilities. The three-month comparative period also reflects an unfavorable foreign exchange impact of approximately $5 million. These unfavorable variances were substantially offset for the nine-month comparative period due to (i) increased volumes and fees associated with placing an additional 1.6 million barrels of NGL storage capacity into service in the second half of
2017
at our Fort Saskatchewan facility, (ii) higher volumetric gains at certain facilities in the
2018
period and (iii) a net favorable foreign exchange impact of approximately $5 million.
|
•
|
Crude Oil Storage.
Revenues decreased by $2 million and $14 million for the
three and nine
months ended
September 30, 2018
, respectively, compared to the same periods in
2017
primarily due to the sale of certain of our Bay Area, California terminal assets in December 2017. These lower results were partially offset in each of the comparative periods by higher revenues from increased activity at our Cushing and St. James terminals.
|
•
|
Rail Terminals.
Revenues increased by $8 million and $18 million for the
three and nine
months ended
September 30, 2018
, respectively, over the same periods in
2017
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 $3 million for the three-month comparative period and decreased by $5 million for the
nine
-month comparative period. The decrease for the nine-month comparative period was primarily due to (i) the June 2017 sale of our Bluewater natural gas storage facility and (ii) the absence of a one-time fee recognized during the first quarter of 2017 related to the early termination of a storage contract at our Pine Prairie facility. These unfavorable impacts were partially offset for the nine-month comparative period and fully offset for the three-month comparative period by the favorable impact of expiring contracts replaced at higher rates and more favorable market conditions for hub services at certain of our natural gas storage facilities.
|
Operating Results
(1)
|
|
Three Months Ended
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||||||||
(in millions, except per barrel data)
|
|
2018
|
|
2017
|
|
$
|
|
%
|
|
|
2018
|
|
2017
|
|
$
|
|
%
|
||||||||||||||
Revenues
|
|
$
|
8,483
|
|
|
$
|
5,574
|
|
|
$
|
2,909
|
|
|
52
|
%
|
|
|
$
|
24,376
|
|
|
$
|
17,757
|
|
|
$
|
6,619
|
|
|
37
|
%
|
Purchases and related costs
|
|
(8,191
|
)
|
|
(5,729
|
)
|
|
(2,462
|
)
|
|
(43
|
)%
|
|
|
(24,076
|
)
|
|
(17,407
|
)
|
|
(6,669
|
)
|
|
(38
|
)%
|
||||||
Field operating costs
|
|
(70
|
)
|
|
(62
|
)
|
|
(8
|
)
|
|
(13
|
)%
|
|
|
(200
|
)
|
|
(193
|
)
|
|
(7
|
)
|
|
(4
|
)%
|
||||||
Segment general and administrative expenses
(2)
|
|
(28
|
)
|
|
(25
|
)
|
|
(3
|
)
|
|
(12
|
)%
|
|
|
(87
|
)
|
|
(77
|
)
|
|
(10
|
)
|
|
(13
|
)%
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Adjustments
(3)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
(Gains)/losses from derivative activities net of inventory valuation adjustments
|
|
(110
|
)
|
|
214
|
|
|
(324
|
)
|
|
**
|
|
|
|
110
|
|
|
(89
|
)
|
|
199
|
|
|
**
|
|
||||||
Long-term inventory costing adjustments
|
|
(10
|
)
|
|
(16
|
)
|
|
6
|
|
|
**
|
|
|
|
(18
|
)
|
|
(2
|
)
|
|
(16
|
)
|
|
**
|
|
||||||
Equity-indexed compensation expense
|
|
4
|
|
|
2
|
|
|
2
|
|
|
**
|
|
|
|
10
|
|
|
6
|
|
|
4
|
|
|
**
|
|
||||||
Net (gain)/loss on foreign currency revaluation
|
|
(3
|
)
|
|
(14
|
)
|
|
11
|
|
|
**
|
|
|
|
5
|
|
|
(27
|
)
|
|
32
|
|
|
**
|
|
||||||
Segment Adjusted EBITDA
|
|
$
|
75
|
|
|
$
|
(56
|
)
|
|
$
|
131
|
|
|
234
|
%
|
|
|
$
|
120
|
|
|
$
|
(32
|
)
|
|
$
|
152
|
|
|
475
|
%
|
Maintenance capital
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
33
|
%
|
|
|
$
|
10
|
|
|
$
|
11
|
|
|
$
|
(1
|
)
|
|
(9
|
)%
|
Segment Adjusted EBITDA per barrel
|
|
$
|
0.66
|
|
|
$
|
(0.54
|
)
|
|
$
|
1.20
|
|
|
222
|
%
|
|
|
$
|
0.35
|
|
|
$
|
(0.10
|
)
|
|
$
|
0.45
|
|
|
450
|
%
|
Average Daily Volumes
(4)
|
|
Three Months Ended
September 30, |
|
Variance
|
|
|
Nine Months Ended
September 30, |
|
Variance
|
||||||||||||||||
(in thousands of barrels per day)
|
|
2018
|
|
2017
|
|
Volumes
|
|
%
|
|
|
2018
|
|
2017
|
|
Volumes
|
|
%
|
||||||||
Crude oil lease gathering purchases
|
|
1,042
|
|
|
929
|
|
|
113
|
|
|
12
|
%
|
|
|
1,034
|
|
|
929
|
|
|
105
|
|
|
11
|
%
|
NGL sales
|
|
195
|
|
|
202
|
|
|
(7
|
)
|
|
(3
|
)%
|
|
|
243
|
|
|
254
|
|
|
(11
|
)
|
|
(4
|
)%
|
Supply and Logistics segment total volumes
|
|
1,237
|
|
|
1,131
|
|
|
106
|
|
|
9
|
%
|
|
|
1,277
|
|
|
1,183
|
|
|
94
|
|
|
8
|
%
|
|
**
|
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 September 30, 2018
|
$
|
65
|
|
|
$
|
74
|
|
Three months ended September 30, 2017
|
$
|
44
|
|
|
$
|
52
|
|
|
|
|
|
||||
Nine months ended September 30, 2018
|
$
|
59
|
|
|
$
|
74
|
|
Nine months ended September 30, 2017
|
$
|
43
|
|
|
$
|
54
|
|
•
|
Crude Oil Operations.
Net revenues from our crude oil supply and logistics operations increased for the comparative three- and nine-month periods presented primarily due to favorable grade differentials, primarily in the Permian Basin and Western Canada, as well as higher lease gathering margins and volumes. For the nine-month comparative period, such favorable impacts more than offset the benefit to the 2017 period of the contango market conditions.
|
•
|
NGL Operations.
Net revenues from our NGL operations increased for the
three and nine
months ended
September 30, 2018
compared to the same periods in
2017
. The three- and nine-month comparative periods were favorably impacted by an audit recovery in 2018 related to a profit-sharing arrangement. The nine-month comparative period was also favorably impacted by (i) lower supply costs at our straddle plants relative to NGL values, (ii) favorable impacts from a wider isobutane/normal butane differential and (iii) modifications made to our contracting strategies in the 2017-2018 heating season.
|
•
|
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) and inventory valuation adjustments, as applicable. See
Note 11
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
|
•
|
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 and nine
months ended
September 30, 2018
compared to the
three and nine
months ended
September 30, 2017
was primarily driven by an increase in third party trucking utilization and higher fuel costs due to longer hauls and increased volumes.
|
•
|
Segment General and Administrative Expenses.
The increase in segment general and administrative expenses for the
three and nine
months ended
September 30, 2018
compared to the
three and nine
months ended
September 30, 2017
was primarily driven by (i) an increase in equity-indexed compensation expense due to the impact of an increase in unit price for the
2018
periods compared to a decrease in unit price for the
2017
periods and (ii) cost increases across various categories.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Gain/(loss) related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option
(1)
|
$
|
(2
|
)
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
—
|
|
Other
|
(1
|
)
|
|
(3
|
)
|
|
5
|
|
|
(6
|
)
|
||||
|
$
|
(3
|
)
|
|
$
|
(1
|
)
|
|
$
|
8
|
|
|
$
|
(6
|
)
|
|
(1)
|
See
Note 11
to our Condensed Consolidated Financial Statements for additional information.
|
|
As of
September 30, 2018 |
||
Availability under senior unsecured revolving credit facility
(1) (2)
|
$
|
1,441
|
|
Availability under senior secured hedged inventory facility
(1) (2)
|
1,078
|
|
|
Amounts outstanding under commercial paper program
|
(60
|
)
|
|
Subtotal
|
2,459
|
|
|
Cash and cash equivalents
|
29
|
|
|
Total
|
$
|
2,488
|
|
|
(1)
|
Represents availability prior to giving effect to amounts outstanding under our commercial paper program, which reduce available capacity under the facilities.
|
(2)
|
Available capacity under the senior unsecured revolving credit facility and the senior secured hedged inventory facility was reduced by outstanding letters of credit of
$159 million
and
$22 million
, respectively.
|
|
Remainder of 2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 and Thereafter
|
|
Total
|
||||||||||||||
Long-term debt and related interest payments
(1)
|
$
|
105
|
|
|
$
|
918
|
|
|
$
|
878
|
|
|
$
|
948
|
|
|
$
|
1,079
|
|
|
$
|
10,190
|
|
|
$
|
14,118
|
|
Leases, rights-of-way easements and other
(2)
|
56
|
|
|
158
|
|
|
130
|
|
|
110
|
|
|
93
|
|
|
366
|
|
|
913
|
|
|||||||
Other obligations
(3)
|
458
|
|
|
513
|
|
|
207
|
|
|
174
|
|
|
128
|
|
|
438
|
|
|
1,918
|
|
|||||||
Subtotal
|
619
|
|
|
1,589
|
|
|
1,215
|
|
|
1,232
|
|
|
1,300
|
|
|
10,994
|
|
|
16,949
|
|
|||||||
Crude oil, NGL and other purchases
(4)
|
3,459
|
|
|
6,596
|
|
|
5,024
|
|
|
4,618
|
|
|
3,984
|
|
|
13,032
|
|
|
36,713
|
|
|||||||
Total
|
$
|
4,078
|
|
|
$
|
8,185
|
|
|
$
|
6,239
|
|
|
$
|
5,850
|
|
|
$
|
5,284
|
|
|
$
|
24,026
|
|
|
$
|
53,662
|
|
|
(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 facilities or commercial paper program) in the amounts above. For additional information regarding our debt obligations, see
Note 9
to our Condensed Consolidated Financial Statements.
|
(2)
|
Leases are primarily for (i) railcars, (ii) land and surface rentals, (iii) office buildings, (iv) pipeline assets and (v) vehicles and trailers. Includes operating and capital leases as defined by FASB guidance, as well as obligations for rights-of-way easements.
|
(3)
|
Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements and (iii) non-cancelable 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 $785 million associated with 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.
|
(4)
|
Amounts are primarily based on estimated volumes and market prices based on average activity during
September
2018
. 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;
|
•
|
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 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;
|
•
|
the failure to consummate, or significant delay in consummating, sales of assets or interests as a part of our strategic divestiture program;
|
•
|
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;
|
•
|
factors affecting demand for natural gas and natural gas storage services and rates;
|
•
|
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
|
$
|
(73
|
)
|
|
$
|
37
|
|
|
$
|
(34
|
)
|
Natural gas
|
(9
|
)
|
|
$
|
9
|
|
|
$
|
(9
|
)
|
|
NGL and other
|
(259
|
)
|
|
$
|
(105
|
)
|
|
$
|
105
|
|
|
Total fair value
|
$
|
(341
|
)
|
|
|
|
|
|
|
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
|
—
|
|
|
|
|
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
|
—
|
|
|
|
|
10.1 *
|
—
|
|
|
|
|
10.2 *
|
—
|
|
|
|
|
10.3 *
|
—
|
|
|
|
|
10.4 *
|
—
|
|
|
|
|
10.5 *
|
—
|
|
|
|
|
10.6 *†
|
—
|
|
|
|
|
10.7 *†
|
—
|
|
|
|
|
10.8 *†
|
—
|
|
|
|
|
10.9 *†
|
—
|
|
|
|
|
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.
|
*
|
Management compensatory plan or arrangement.
|
|
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)
|
|
|
|
November 7, 2018
|
|
|
|
|
|
|
By:
|
/s/ Al Swanson
|
|
|
Al Swanson,
|
|
|
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
|
|
|
(Principal Financial Officer)
|
|
|
|
November 7, 2018
|
|
|
|
|
|
|
By:
|
/s/ Chris Herbold
|
|
|
Chris Herbold,
|
|
|
Senior Vice President and Chief Accounting Officer of Plains All American GP LLC
|
|
|
(Principal Accounting Officer)
|
|
|
|
November 7, 2018
|
|
1 Year Plains All American Pipe... Chart |
1 Month Plains All American Pipe... Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions