PAA Also Furnishes 2018 Full-Year
Guidance
Plains All American Pipeline, L.P. (NYSE: PAA) and Plains GP
Holdings (NYSE: PAGP) today reported fourth-quarter and full-year
2017 results.
Fourth-Quarter and Full-Year 2017
Highlights
- Delivered operating and financial
performance in line with to slightly ahead of 4Q17
expectations;
- Reduced total debt by $1.5 billion
during 4Q17; exited 2017 with $3.0 billion of liquidity
- Retired $950 million of senior
notes
- Reduced short-term/inventory debt by
~$200 million compared to September 30, 2017 (~$375 million
relative to the June 30, 2017 balance);
- Completed ~$1.1 billion in targeted
asset sales (~$700 million since August 2017); advancing efforts on
additional 2018 sales;
- Completed construction and placed the
new Diamond and STACK JV pipelines into service and completed
capacity expansions for the Cactus I and BridgeTex pipelines,
adding over 275,000 barrels per day to PAA’s net transportation
capacity; and
- Obtained long-term minimum volume
commitments (“MVCs”) to sanction construction of the Cactus II
pipeline and the extension/looping of the Sunrise pipeline
system.
“We are pleased to report that PAA finished the year on a strong
note, having made significant progress on the plans we outlined in
August of 2017,” stated Willie Chiang, Executive Vice President and
Chief Operating Officer of Plains All American Pipeline.
“We remain on track to achieve our deleveraging objectives and
targeted credit metrics by early 2019 while maintaining substantial
distribution coverage underpinned by predominantly fee-based cash
flow. Additionally, execution of our capital program, which
includes several recently announced Permian projects, and robust
Permian fundamentals will drive momentum for PAA’s continued growth
in 2018 and beyond.”
Plains All American Pipeline,
L.P.
Summary Financial
Information (unaudited)
(in millions, except per unit data)
Three Months Ended
December 31,
%
Twelve Months Ended
December 31,
% GAAP Results
2017 2016 Change
2017 2016 Change Net income
attributable to PAA $ 191 $ 126 52 % $ 856 $ 726 18 % Diluted net
income per common unit $ 0.19 $ 0.14 36 % $ 0.95 $ 0.43 121 %
Diluted weighted average common units outstanding 726 662
10 % 718 466 54 % Distribution per common unit
declared for the period $ 0.30 $ 0.55 (45 )% $ 1.70
$ 2.50 (32 )%
Three Months Ended
December 31,
%
Twelve Months Ended
December 31,
% Non-GAAP Results (1)
2017 2016 Change 2017
2016 Change Adjusted net income attributable to PAA $
241 $ 278 (13 )% $ 849 $ 1,062 (20 )% Diluted adjusted net income
per common unit $ 0.26 $ 0.37 (30 )% $ 0.94 $ 1.14 (18 )% Adjusted
EBITDA $ 631 $ 600 5 % $ 2,082 $ 2,169 (4 )%
_____________________________
(1) See the section of this release entitled “Non-GAAP
Financial Measures and Selected Items Impacting Comparability” and
the tables attached hereto for information regarding certain
selected items that PAA believes impact comparability of financial
results between reporting periods, as well as for information
regarding non-GAAP financial measures (such as adjusted EBITDA) and
their reconciliation to the most directly comparable measures as
reported in accordance with GAAP.
Segment adjusted EBITDA for the fourth quarter and full year of
2017 and 2016 is presented below:
Summary of
Selected Financial Data by Segment (unaudited)
(in millions)
Three Months
EndedDecember 31, 2017 Three Months
EndedDecember 31, 2016 Transportation
Facilities
Supply and
Logistics
Transportation Facilities
Supply and
Logistics
Segment adjusted EBITDA $ 354 $ 184 $ 92 $ 278
$ 171 $ 151
Percentage change in segment
adjusted EBITDA versus
2016
period
27 % 8 % (39 )%
Twelve Months EndedDecember 31, 2017 Twelve
Months EndedDecember 31, 2016 Transportation
Facilities
Supply and
Logistics
Transportation Facilities
Supply and
Logistics
Segment adjusted EBITDA $ 1,287 $ 734 $ 60 $
1,141 $ 667 $ 359
Percentage change in segment
adjusted EBITDA versus
2016
period
13 % 10 % (83 )%
Fourth-quarter 2017 Transportation segment adjusted EBITDA
increased by 27% versus comparable 2016 results. This increase was
primarily driven by increased volume on our Permian Basin systems,
in addition to contributions from our Eagle Ford JV system, which
receives Permian volumes from our Cactus pipeline. This increase
was partially offset by a one-time contract settlement in the
fourth quarter and the sale of non-core assets in our Rocky
Mountain region.
Fourth-quarter 2017 Facilities segment adjusted EBITDA increased
by 8% versus comparable 2016 results. This increase was primarily
driven by increased NGL storage and fractionation services and
higher throughput fees and additional storage capacity at Cushing
and Patoka. These increases were partially offset by decreased rail
terminal revenue and the impact of a natural gas storage asset sale
completed in June 2017.
Fourth-quarter 2017 Supply and Logistics segment adjusted EBITDA
decreased by 39% versus comparable 2016 results due to crude oil
and NGL margin compression and reduced arbitrage opportunities.
2018 Full-Year Guidance
The table below presents our full-year
2018 financial and operating guidance:
Financial and
Operating Guidance (unaudited)
(in millions, except per unit and per
barrel data)
Twelve Months Ended December
31, 2016 2017 2018
(G) + / -
Segment Adjusted EBITDA Transportation $ 1,141
$ 1,287 $ 1,535 Facilities 667 734 665
Fee-based $ 1,808 $ 2,021
$ 2,200 Supply and Logistics 359 60 100 Other
income/(expense), net 2 1 —
Adjusted
EBITDA (1) $ 2,169 $
2,082 $ 2,300 Interest expense,
net (2) (451 ) (483 ) (425 ) Maintenance capital (186 ) (247 ) (215
) Current income tax expense (85 ) (28 ) (30 ) Other (33 )
(12 ) 5
Implied DCF (1) $
1,414 $ 1,312 $ 1,635 Preferred
unit cash distributions paid (3) — (5 ) (160 ) General partner cash
distributions (565 ) — —
Implied DCF
Available to Common Unitholders $ 849
$ 1,307 $ 1,475
Implied DCF per Common Unit (1) $ 1.83 $ 1.82 $ 2.03
Implied DCF per Common Unit and Common Equivalent Unit
(1) $ 1.63 $ 1.67 $ 1.99
Distributions per Common
Unit (4) $ 2.65 $ 1.95 $ 1.20
Common Unit
Distribution Coverage Ratio 0.87x 0.94x 1.70x
Operating Data Transportation Average daily volumes
(MBbls/d) 4,637 5,186 5,925 Segment Adjusted EBITDA per barrel $
0.67 $ 0.68 $ 0.71
Facilities Average capacity
(MMBbls/Mo) 127 130 125 Segment Adjusted EBITDA per barrel $ 0.44 $
0.47 $ 0.44
Supply and Logistics Average daily
volumes (MBbls/d) 1,153 1,219 1,275 Segment Adjusted EBITDA per
barrel $ 0.85 $ 0.13 $ 0.21
Expansion Capital
$ 1,405 $ 1,135 $ 1,400
First-Quarter Adjusted EBITDA as Percentage of Full
Year 29 % 25 % 25 %
_____________________________
(G) 2018 Guidance forecasts are intended to be + / -
amounts. (1) See the section of this release entitled
“Non-GAAP Financial Measures and Selected Items Impacting
Comparability” and the Non-GAAP Reconciliation tables attached
hereto for information regarding non-GAAP financial measures and,
for the historical 2016 and 2017 periods, their reconciliation to
the most directly comparable measures as reported in accordance
with GAAP. We do not provide a reconciliation of non-GAAP financial
measures to the equivalent GAAP financial measures on a
forward-looking basis as it is impractical to forecast certain
items that we have defined as “Selected Items Impacting
Comparability” without unreasonable effort, due to the uncertainty
and inherent difficulty of predicting the occurrence and financial
impact of and the periods in which such items may be recognized.
Thus, a reconciliation of non-GAAP financial measures to the
equivalent GAAP financial measures could result in disclosure that
could be imprecise or potentially misleading. (2) Excludes
certain non-cash items impacting interest expense such as
amortization of debt issuance costs and terminated interest rate
swaps. (3) Cash distributions paid to our preferred
unitholders during the year presented. The distribution requirement
of our Series A preferred units was paid-in-kind for all 2016 and
2017 quarterly distributions. Distributions on our Series A
preferred units must be paid in cash beginning with the May 2018
quarterly distribution. The 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. A pro-rated
initial distribution on the Series B preferred units was paid on
November 15, 2017. (4) Cash distributions per common unit
paid during 2016 and 2017. 2018(G) reflects the current
distribution rate held constant.
Plains GP Holdings
PAGP owns an indirect non-economic controlling interest in PAA’s
general partner and an indirect limited partner interest in PAA. As
the control entity of PAA, PAGP consolidates PAA’s results into its
financial statements, which is reflected in the condensed
consolidating balance sheet and income statement tables included at
the end of this release. Information regarding PAGP’s distributions
is reflected below:
Q4 2017
Q3 2017 Q4 2016
Distribution per Class A share declared
for the period
$ 0.30 $ 0.30 $ 0.55
Q4 2017 distribution
percentage change from prior periods — % (45 )%
Additionally, following the enactment of the Tax Cuts and Jobs
Act of 2017 and the resulting decrease in the federal income tax
rate from 35% to 21%, in the fourth quarter of 2017 PAGP
re-measured its deferred tax asset and recorded deferred income tax
expense of $823 million. This re-measurement is non-cash and does
not affect the timing of when PAGP is expected to pay taxes, which
we do not currently expect to occur within the next 10 years.
Conference Call
PAA and PAGP will hold a conference call at 10:00 a.m. CT on
Wednesday, February 7, 2018 to discuss the following items:
1. PAA’s fourth-quarter 2017 and full-year 2017 performance;
2. Financial and operating guidance for the full year of
2018;
3. Capitalization and liquidity; and
4. PAA’s and PAGP’s outlook for the future.
Conference Call Webcast Instructions
To access the internet webcast please go to https://event.webcasts.com/starthere.jsp?ei=1176062&tp.
Alternatively, the webcast can be accessed at
www.plainsallamerican.com, under the Investor Relations section of
the website (Navigate to: Investor Relations / either PAA or PAGP /
News & Events / Quarterly Earnings). Following the live
webcast, an audio replay in MP3 format will be available on the
website within two hours after the end of the call and will be
accessible for a period of 365 days.
Non-GAAP Financial Measures and Selected Items Impacting
Comparability
To supplement our financial information presented in accordance
with GAAP, management uses additional measures known as “non-GAAP
financial measures” in its evaluation of past performance and
prospects for the future. The primary additional measures used by
management are earnings before interest, taxes, depreciation and
amortization (including our proportionate share of depreciation and
amortization and gains or losses on significant asset sales of
unconsolidated entities) and adjusted for certain selected items
impacting comparability (“Adjusted EBITDA”) and implied
distributable cash flow (“DCF”).
Management believes that the presentation of such additional
financial measures provides useful information to investors
regarding our performance and results of operations because these
measures, when used to supplement related GAAP financial measures,
(i) provide additional information about our core operating
performance and ability to fund distributions to our unitholders
through cash generated by our operations and (ii) provide investors
with the same financial analytical framework upon which management
bases financial, operational, compensation and planning/budgeting
decisions. We also present these and additional non-GAAP financial
measures, including adjusted net income attributable to PAA; basic
and diluted adjusted net income per common unit; implied DCF
available to common unitholders; implied DCF per common unit; and
implied DCF per common unit and common equivalent unit, as they are
measurements that investors, rating agencies and debt holders have
indicated are useful in assessing us and our results of operations.
These non-GAAP measures may exclude, for example, (i) charges for
obligations that are expected to be settled with the issuance of
equity instruments, (ii) gains or losses on derivative instruments
that are related to underlying activities in another period (or the
reversal of such adjustments from a prior period), the
mark-to-market related to our Preferred Distribution Rate Reset
Option, gains and losses on derivatives that are related to
investing activities (such as the purchase of linefill) and
inventory valuation adjustments, as applicable, (iii) long-term
inventory costing adjustments, (iv) items that are not indicative
of our core operating results and business outlook and/or (v) other
items that we believe should be excluded in understanding our core
operating performance. These measures may further be adjusted to
include amounts related to deficiencies associated with minimum
volume commitments whereby we have billed the counterparties for
their deficiency obligation and such amounts are recognized as
deferred revenue in “Accounts payable and accrued liabilities” on
our Consolidated Financial Statements. Such amounts are presented
net of applicable amounts subsequently recognized into revenue.
Furthermore, the calculation of these measures contemplates tax
effects as a separate reconciling item, where applicable. We have
defined all such items as “selected items impacting comparability.”
Due to the nature of the selected items, certain selected items
impacting comparability may impact certain non-GAAP financial
measures, referred to as adjusted results, but not impact other
non-GAAP financial measures. We do not necessarily consider all of
our selected items impacting comparability to be non-recurring,
infrequent or unusual, but we believe that an understanding of
these selected items impacting comparability is material to the
evaluation of our operating results and prospects.
Although we present selected items impacting comparability that
management considers in evaluating our performance, you should also
be aware that the items presented do not represent all items that
affect comparability between the periods presented. Variations in
our operating results are also caused by changes in volumes,
prices, exchange rates, mechanical interruptions, acquisitions,
expansion projects and numerous other factors. These types of
variations are not separately identified in this release, but will
be discussed, as applicable, in management’s discussion and
analysis of operating results in our Annual Report on
Form 10-K.
Our definition and calculation of certain non-GAAP financial
measures may not be comparable to similarly-titled measures of
other companies. Adjusted EBITDA, Implied DCF and other
non-GAAP financial performance measures are reconciled to Net
Income (the most directly comparable measure as reported in
accordance with GAAP) for the historical periods presented in the
tables attached to this release, and should be viewed in addition
to, and not in lieu of, our Consolidated Financial Statements and
notes thereto. In addition, we encourage you to visit our website
at www.plainsallamerican.com (in particular the section under
“Financial Information” entitled “Non-GAAP Reconciliations” within
the Investor Relations tab), which presents a reconciliation of our
commonly used non-GAAP and supplemental financial measures.
Forward-Looking Statements
Except for the historical information contained herein, the
matters discussed in this release consist of forward-looking
statements that involve certain risks and uncertainties that could
cause actual results or outcomes to differ materially from results
or outcomes anticipated in the forward-looking statements. These
risks and uncertainties include, among other things, 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 producer
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); maintenance of our credit rating and
ability to receive open credit from our suppliers and trade
counterparties; 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 and natural gas and resulting changes in pricing
conditions or transportation throughput requirements; 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; 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 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
failure to consummate, or significant delay in consummating, sales
of assets or interests as a part of our strategic divestiture
program; the impact of current and future laws, rulings,
governmental regulations, accounting standards and statements, and
related interpretations; 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 availability of, and our ability to consummate,
acquisition or combination opportunities; the effectiveness of our
risk management activities; shortages or cost increases of
supplies, materials or labor; 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 as discussed in the
Partnerships’ filings with the Securities and Exchange
Commission.
Plains All American Pipeline, L.P. is a publicly traded master
limited partnership that owns and operates midstream energy
infrastructure and provides logistics services for crude oil,
natural gas liquids (“NGL”) and natural gas. PAA owns an extensive
network of pipeline transportation, terminalling, storage and
gathering assets in key crude oil and NGL producing basins and
transportation corridors and at major market hubs in the United
States and Canada. On average, PAA handles over 5 million barrels
per day of crude oil and NGL in its Transportation segment. PAA is
headquartered in Houston, Texas. More information is available at
www.plainsallamerican.com.
Plains GP Holdings is a publicly traded entity that owns an
indirect, non-economic controlling general partner interest in PAA
and an indirect limited partner interest in PAA, one of the largest
energy infrastructure and logistics companies in North America.
PAGP is headquartered in Houston, Texas. More information is
available at www.plainsallamerican.com.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016 REVENUES $ 7,605 $ 5,952 $ 26,223
$ 20,182
COSTS AND EXPENSES Purchases and related
costs 6,746 5,234 22,985 17,233 Field operating costs 307 289 1,183
1,182 General and administrative expenses 66 68 276 279
Depreciation and amortization 225 143 626 494
Total costs and expenses 7,344 5,734 25,070 19,188
OPERATING INCOME 261 218 1,153 994
OTHER
INCOME/(EXPENSE) Equity earnings in unconsolidated entities 90
61 290 195 Interest expense, net (120 ) (127 ) (510 ) (467 ) Other
income/(expense), net (26 ) (14 ) (31 ) 33
INCOME
BEFORE TAX 205 138 902 755 Current income tax expense (19 ) (41
) (28 ) (85 ) Deferred income tax benefit/(expense) 5 30
(16 ) 60
NET INCOME 191 127 858 730 Net
income attributable to noncontrolling interests — (1 ) (2 )
(4 )
NET INCOME ATTRIBUTABLE TO PAA $ 191 $ 126
$ 856 $ 726
NET INCOME PER COMMON
UNIT: Net income allocated to common unitholders — Basic $ 138
$ 91 $ 685 $ 200 Basic weighted average common units outstanding
725 660 717 464 Basic net income per common unit $ 0.19 $
0.14 $ 0.96 $ 0.43 Net income allocated
to common unitholders — Diluted $ 138 $ 91 $ 685 $ 200 Diluted
weighted average common units outstanding 726 662 718 466 Diluted
net income per common unit $ 0.19 $ 0.14 $ 0.95
$ 0.43
NON-GAAP ADJUSTED
RESULTS
(in millions, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017 2016 Adjusted net income
attributable to PAA $ 241 $ 278 $ 849 $ 1,062
Diluted adjusted net income per common unit $ 0.26
$ 0.37 $ 0.94 $ 1.14 Adjusted
EBITDA $ 631 $ 600 $ 2,082 $ 2,169
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATED BALANCE SHEET DATA
(in millions)
December 31,
2017
December 31,
2016
ASSETS Current assets $ 4,000 $ 4,272 Property and
equipment, net 14,089 13,872 Goodwill 2,566 2,344 Investments in
unconsolidated entities 2,756 2,343 Linefill and base gas 872
896
Long-term inventory 164 193 Other long-term assets, net 904
290 Total assets $ 25,351 $ 24,210
LIABILITIES AND
PARTNERS' CAPITAL Current liabilities $ 4,531 $ 4,664 Senior
notes, net of unamortized discounts and debt issuance costs 8,933
9,874 Other long-term debt 250 250 Other long-term liabilities and
deferred credits 679 606 Total liabilities $ 14,393 $ 15,394
Partners' capital excluding noncontrolling interests 10,958
8,759 Noncontrolling interests — 57 Total partners' capital
10,958 8,816 Total liabilities and partners' capital $
25,351 $ 24,210
DEBT
CAPITALIZATION RATIOS
(in millions)
December 31,
2017
December 31,
2016
Short-term debt (1) $ 737 $ 1,715 Long-term debt 9,183
10,124 Total debt $ 9,920 $ 11,839
Long-term debt $ 9,183 $ 10,124 Partners' capital 10,958
8,816 Total book capitalization $ 20,141 $ 18,940
Total book capitalization, including short-term debt $
20,878 $ 20,655 Long-term debt-to-total book
capitalization 46 % 53 % Total debt-to-total book capitalization,
including short-term debt 48 % 57 %
_____________________________
(1) As of December 31, 2017 and 2016, short-term debt
includes borrowings of approximately $523 million and $1,303
million, respectively, for short-term hedged inventory purchases
and borrowings of approximately $212 million and $410 million,
respectively, for cash margin deposits with our clearing brokers,
which are associated with financial derivatives used for hedging
purposes.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
OPERATING
DATA (1)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016 Transportation segment (average daily volumes in
thousands of barrels per day): Tariff activities volumes Crude
oil pipelines (by region): Permian Basin (2) 3,219 2,197 2,855
2,146 South Texas / Eagle Ford (2) 418 284 360 284 Central (2) 424
397 420 394 Gulf Coast 312 373 349 497 Rocky Mountain (2) 317 454
393 449 Western 179 171 184 188 Canada 330 374 352
381 Crude oil pipelines 5,199 4,250 4,913 4,339 NGL
pipelines 172 190 170 184 Tariff activities
total volumes 5,371 4,440 5,083 4,523 Trucking volumes 106
118 103 114 Transportation segment total volumes
5,477 4,558 5,186 4,637
Facilities
segment (average monthly volumes): Liquids storage (average
monthly capacity in millions of barrels) 114 110 112
107 Natural gas storage (average monthly working capacity in
billions of cubic feet) 67 97 82 97 NGL
fractionation (average volumes in thousands of barrels per day) 127
122 126 115 Facilities segment total volumes
(average monthly volumes in millions of barrels) (3) 129 129
130 127
Supply and Logistics segment
(average daily volumes in thousands of barrels per day): Crude
oil lease gathering purchases 994 895 945 894 NGL sales 335
346 274 259 Supply and Logistics segment total
volumes 1,329 1,241 1,219 1,153
_____________________________
(1) Average volumes are calculated as total volumes for the
period (attributable to our interest) divided by the number of days
or months in the period. (2) Region includes volumes
(attributable to our interest) from pipelines owned by
unconsolidated entities. (3) 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.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
COMPUTATION OF
BASIC AND DILUTED NET INCOME PER COMMON UNIT
(1)
(in millions, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016 Basic Net Income per Common Unit Net income
attributable to PAA $ 191 $ 126 $ 856 $ 726 Distributions to Series
A preferred unitholders (37 ) (34 ) (142 ) (122 ) Distributions to
Series B preferred unitholders (11 ) — (11 ) — Distributions to
general partner — — — (412 ) Other (5 ) (1 ) (18 ) 8 Net
income allocated to common unitholders $ 138 $ 91 $
685 $ 200 Basic weighted average common units
outstanding 725 660 717 464 Basic net income per common unit
$ 0.19 $ 0.14 $ 0.96 $ 0.43
Diluted Net Income per Common Unit Net income attributable
to PAA $ 191 $ 126 $ 856 $ 726 Distributions to Series A preferred
unitholders (37 ) (34 ) (142 ) (122 ) Distributions to Series B
preferred unitholders (11 ) — (11 ) — Distributions to general
partner — — — (412 ) Other (5 ) (1 ) (18 ) 8 Net income
allocated to common unitholders $ 138 $ 91 $ 685
$ 200 Basic weighted average common units
outstanding 725 660 717 464 Effect of dilutive securities: LTIP
units (2) 1 2 1 2 Diluted weighted
average common units outstanding 726 662 718
466 Diluted net income per common unit (3) $ 0.19
$ 0.14 $ 0.95 $ 0.43
_____________________________
(1) We calculate net income allocated to common unitholders
based on the distributions pertaining to the current period’s net
income (whether paid in cash or in-kind). After adjusting for the
appropriate period’s distributions, the remaining undistributed
earnings or excess distributions over earnings (“undistributed
loss”), if any, are allocated to the general partner (for periods
prior to the Simplification Transactions), 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. The Simplification
Transactions, which closed on November 15, 2016, simplified our
governance structure and permanently eliminated our IDRs and the
economic rights associated with our 2% general partner interest. As
such, beginning with the distribution pertaining to the fourth
quarter of 2016, our general partner is no longer entitled to
receive distributions on these interests. (2) Our Long-term
Incentive Plan (“LTIP”) awards that contemplate the issuance of
common units are considered dilutive unless (i) vesting occurs only
upon the satisfaction of a performance condition and (ii) that
performance condition has yet to be satisfied. LTIP awards that are
deemed to be dilutive are reduced by a hypothetical unit repurchase
based on the remaining unamortized fair value, as prescribed by the
treasury stock method in guidance issued by the FASB. (3)
The possible conversion of our Series A preferred units was
excluded from the calculation of diluted net income per common unit
for the three and twelve months ended December 31, 2017 and 2016 as
the effect was antidilutive.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED
FINANCIAL DATA BY SEGMENT
(in millions)
Three Months
EndedDecember 31, 2017 Three Months
EndedDecember 31, 2016 Transportation
Facilities
Supply and
Logistics
Transportation Facilities
Supply and
Logistics
Revenues (1) $ 458 $ 299 $ 7,308 $ 396 $ 290 $ 5,665 Purchases and
related costs (1) (48 ) (4 ) (7,151 ) (25 ) (9 ) (5,596 ) Field
operating costs (1) (2) (158 ) (91 ) (61 ) (136 ) (91 ) (65 )
Segment general and administrative
expenses (2) (3)
(24 ) (18 ) (24 ) (25 ) (16 ) (27 )
Equity earnings in unconsolidated
entities
90 — — 61 — — Adjustments: (4)
Depreciation and amortization of
unconsolidated entities
13 — — 13 — —
(Gains)/losses from derivative activities
net of inventory valuation adjustments
— — 40 — (2 ) 217
Long-term inventory costing
adjustments
— — (22 ) — — (51 )
Deficiencies under minimum volume
commitments, net
— (3 ) — (11 ) (3 ) —
Equity-indexed compensation expense
3 1 1 5 2 3
Net loss on foreign currency
revaluation
— — 1 — — 5 Line 901 incident 20 — — —
— — Segment adjusted EBITDA $ 354 $ 184
$ 92 $ 278 $ 171 $ 151
Maintenance capital $ 31 $ 20 $ 2 $ 35
$ 23 $ —
_____________________________
(1) Includes intersegment amounts. (2) Field
operating costs and Segment general and administrative expenses
include equity-indexed compensation expense. (3) 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. (4) Represents adjustments
utilized by our Chief Operating Decision Maker (“CODM”) in the
evaluation of segment results. Many of these adjustments are also
considered selected items impacting comparability when calculating
consolidated non-GAAP financial measures such as Adjusted EBITDA.
See the “Selected Items Impacting Comparability” table for
additional discussion.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED
FINANCIAL DATA BY SEGMENT
(in millions)
Twelve Months
EndedDecember 31, 2017 Twelve Months
EndedDecember 31, 2016 Transportation
Facilities
Supply and
Logistics
Transportation Facilities
Supply and
Logistics
Revenues (1) $ 1,718 $ 1,173 $ 25,065 $ 1,584 $ 1,107 $ 19,018
Purchases and related costs (1) (123 ) (24 ) (24,557 ) (94 ) (26 )
(18,627 ) Field operating costs (1) (2) (593 ) (350 ) (254 ) (551 )
(352 ) (292 ) Segment general and administrative expenses (2) (3)
(101 ) (73 ) (102 ) (103 ) (68 ) (108 ) Equity earnings in
unconsolidated entities 290 — — 195 — — Adjustments: (4)
Depreciation and amortization of unconsolidated entities 45 — — 50
— — (Gains)/losses from derivative activities net of inventory
valuation adjustments — 4 (50 ) — (2 ) 406 Long-term inventory
costing adjustments — — (24 ) — — (58 ) Deficiencies under minimum
volume commitments, net 2 — — 44 2 — Equity-indexed compensation
expense 11 4 8 16 7 10 Net (gain)/loss on foreign currency
revaluation — — (26 ) — (1 ) 10 Line 901 incident 32 — — — — —
Significant acquisition-related expenses 6 — —
— — — Segment adjusted EBITDA $ 1,287 $
734 $ 60 $ 1,141 $ 667 $ 359
Maintenance capital $ 120 $ 114 $ 13 $
121 $ 55 $ 10
_____________________________
(1) Includes intersegment amounts. (2) Field
operating costs and Segment general and administrative expenses
include equity-indexed compensation expense. (3) 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. (4) Represents adjustments
utilized by our CODM in the evaluation of segment results. Many of
these adjustments are also considered selected items impacting
comparability when calculating consolidated non-GAAP financial
measures such as Adjusted EBITDA. See the “Selected Items Impacting
Comparability” table for additional discussion.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED ITEMS
IMPACTING COMPARABILITY
(in millions)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016 Selected Items Impacting Comparability:
(1) Gains/(losses) from derivative activities net of
inventory valuation adjustments (2) $ (28 ) $ (227 ) $ 59 $ (374 )
Long-term inventory costing adjustments (3) 22 51 24 58
Deficiencies under minimum volume commitments, net (4) 3 14 (2 )
(46 ) Equity-indexed compensation expense (5) (5 ) (10 ) (23 ) (33
) Net gain/(loss) on foreign currency revaluation (6) — (7 ) 21 (8
) Line 901 incident (7) (20 ) — (32 ) — Significant
acquisition-related expenses (8) — — (6 ) — Net loss on early
repayment of senior notes (9) (40 ) — (40 ) —
Selected items impacting comparability - Adjusted EBITDA $ (68 ) $
(179 ) $ 1 $ (403 ) Losses from derivative activities (2) — — (10 )
— Tax effect on selected items impacting comparability 18 27
16 67 Selected items impacting comparability -
Adjusted net income attributable to PAA $ (50 ) $ (152 ) $ 7
$ (336 )
_____________________________
(1) Certain of our non-GAAP financial measures may not be
impacted by each of the selected items impacting comparability.
(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 results. 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.
(3) We carry crude oil and NGL inventory 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. (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 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.
(6) During the periods presented, there were fluctuations in
the value of the Canadian dollar to the U.S. dollar, 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. (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. (8) Includes acquisition-related expenses
associated with the Alpha Crude Connector acquisition. (9)
Includes net losses incurred in connection with the early
redemption of our (i) $600 million, 6.50% senior notes due May 2018
and (ii) $350 million, 8.75% senior notes due May 2019.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
NON-GAAP
RECONCILIATIONS
(in millions, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016 Net Income to Adjusted EBITDA and Implied DCF
Reconciliation Net Income $ 191 $ 127 $ 858 $ 730 Interest
expense, net 120 127 510 467 Income tax expense 14 11 44 25
Depreciation and amortization 225 143 626 494 Depreciation and
amortization of unconsolidated entities (1) 13 13 45 50 Selected
items impacting comparability - Adjusted EBITDA (2) 68 179
(1 ) 403 Adjusted EBITDA $ 631 $ 600 $
2,082 $ 2,169 Interest expense, net (3) (116 ) (123 )
(483 ) (451 ) Maintenance capital (53 ) (58 ) (247 ) (186 ) Current
income tax expense (19 ) (41 ) (28 ) (85 ) Adjusted equity earnings
in unconsolidated entities, net of distributions (4) (19 ) (9 ) (10
) (29 ) Distributions to noncontrolling interests — (1 ) (2
) (4 ) Implied DCF (5) $ 424 $ 368 $ 1,312 $ 1,414 Preferred unit
cash distributions (6) (5 ) — (5 ) — General partner cash
distributions (7) — (101 ) — (565 ) Implied DCF
Available to Common Unitholders $ 419 $ 267 $ 1,307
$ 849 Implied DCF per Common Unit (8) $ 0.58 $
0.40 $ 1.82 $ 1.83 Implied DCF per Common Unit and Common
Equivalent Unit (9) $ 0.53 $ 0.37 $ 1.67 $ 1.63 Cash
Distribution Paid per Common Unit $ 0.30 $ 0.55 $ 1.95 $ 2.65
Common Unit Cash Distributions (10) $ 218 $ 328 $ 1,386 $ 1,627
Common Unit Distribution Coverage Ratio 1.92x 1.12x 0.94x 0.87x
Implied DCF Excess / (Shortage) $ 201 $ 40 $ (79 ) $ (213 )
_____________________________
(1) Adjustment to add back our proportionate share of
depreciation and amortization expense and gains or losses on
significant asset sales of unconsolidated entities. (2)
Certain of our non-GAAP financial measures may not be impacted by
each of the selected items impacting comparability. (3)
Excludes certain non-cash items impacting interest expense such as
amortization of debt issuance costs and terminated interest rate
swaps. (4) Represents the difference between non-cash equity
earnings in unconsolidated entities (adjusted for our proportionate
share of depreciation and amortization and gains or losses on
significant asset sales) and cash distributions received from such
entities. (5) Including net costs recognized during the
periods related to the Line 901 incident that occurred in May 2015,
Implied DCF would have been $404 million and $1,280 million for the
three and twelve months ended December 31, 2017, respectively.
(6) Cash distributions paid to our preferred unitholders
during the period presented. The $0.5250 quarterly ($2.10
annualized) per unit distribution requirement of our Series A
preferred units has been paid-in-kind for each quarterly
distribution since their issuance; as such, no Series A preferred
unit distributions are included for any periods presented.
Distributions on our Series A preferred units must be paid in cash
beginning with the May 2018 quarterly distribution. The $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. A pro-rated initial
distribution on the Series B preferred units was paid on November
15, 2017. (7) The Simplification Transactions, which closed
on November 15, 2016, simplified our governance structure and
permanently eliminated our incentive distribution rights (IDRs) and
the economic rights associated with our 2% general partner
interest. (8) Implied DCF Available to Common Unitholders
for the period divided by the weighted average common units
outstanding for the periods of 725 million, 660 million, 717
million and 464 million, respectively. (9) Implied DCF
Available to Common Unitholders for the period, adjusted for Series
A preferred unit cash distributions paid (if any), divided by the
weighted average common units and common equivalent units
outstanding for the periods of 794 million, 724 million, 784
million and 522 million, respectively. Our Series A preferred units
are convertible into common units, generally on a one-for-one basis
and subject to customary anti-dilution adjustments, at any time
after January 28, 2018, in whole or in part, subject to certain
minimum conversion amounts. (10) Cash distributions paid
during the period presented. For the three and twelve months ended
December 31, 2016, includes $101 million and $565 million,
respectively, of cash distributions paid to the general partner
during the period.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
NON-GAAP
RECONCILIATIONS (continued)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016
Net Income Per Common Unit to Implied
DCF Per Common Unit
and Common Equivalent Unit
Reconciliation
Basic net income per common unit $ 0.19 $ 0.14 $ 0.96 $ 0.43
Reconciling items per common unit (1) (2) 0.39 0.26
0.86 1.40 Implied DCF per common unit $ 0.58 $ 0.40
$ 1.82 $ 1.83 Basic net income per common unit
$ 0.19 $ 0.14 $ 0.96 $ 0.43 Reconciling items per common unit and
common equivalent unit (1) (3) 0.34 0.23 0.71
1.20 Implied DCF per common unit and common equivalent unit $ 0.53
$ 0.37 $ 1.67 $ 1.63
_____________________________
(1) Represents adjustments to Net Income to calculate
Implied DCF Available to Common Unitholders. See the “Net Income to
Adjusted EBITDA and Implied DCF Reconciliation” table for
additional information. (2) Based on weighted average common
units outstanding for the period of 725 million, 660 million, 717
million and 464 million, respectively. (3) Based on weighted
average common units outstanding for the period, as well as
weighted average Series A preferred units outstanding for the
period of 69 million, 64 million, 67 million and 58 million,
respectively.
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016
Net Income Per Common Unit to Adjusted
Net Income Per
Common Unit
Reconciliation
Basic net income per common unit $ 0.19 $ 0.14 $ 0.96 $ 0.43
Selected items impacting comparability per common unit (1) 0.07
0.23 (0.01 ) 0.72 Basic adjusted net income per
common unit $ 0.26 $ 0.37 $ 0.95 $ 1.15
Diluted net income per common unit $ 0.19 $ 0.14 $ 0.95 $ 0.43
Selected items impacting comparability per common unit (1) 0.07
0.23 (0.01 ) 0.71 Diluted adjusted net income per
common unit $ 0.26 $ 0.37 $ 0.94 $ 1.14
_____________________________
(1) See the “Selected Items Impacting Comparability” and the
“Computation of Basic and Diluted Adjusted Net Income Per Common
Unit” tables for additional information.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
COMPUTATION OF
BASIC AND DILUTED ADJUSTED NET INCOME PER COMMON UNIT
(1)
(in millions, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2017 2016 2017
2016 Basic Adjusted Net Income per Common Unit Net
income attributable to PAA $ 191 $ 126 $ 856 $ 726 Selected items
impacting comparability - Adjusted net income attributable to PAA
(2) 50 152 (7 ) 336 Adjusted net income
attributable to PAA $ 241 $ 278 $ 849 $ 1,062 Distributions to
Series A preferred unitholders (37 ) (34 ) (142 ) (122 )
Distributions to Series B preferred unitholders (11 ) — (11 ) —
Distributions to general partner — — — (412 ) Other (5 ) (1 ) (17 )
5 Adjusted net income allocated to common unitholders $ 188
$ 243 $ 679 $ 533 Basic weighted
average common units outstanding 725 660 717 464 Basic
adjusted net income per common unit $ 0.26 $ 0.37 $
0.95 $ 1.15
Diluted Adjusted Net Income per
Common Unit Net income attributable to PAA $ 191 $ 126 $ 856 $
726 Selected items impacting comparability - Adjusted net income
attributable to PAA (2) 50 152 (7 ) 336
Adjusted net income attributable to PAA $ 241 $ 278 $ 849 $ 1,062
Distributions to Series A preferred unitholders (37 ) (34 ) (142 )
(122 ) Distributions to Series B preferred unitholders (11 ) — (11
) — Distributions to general partner — — — (412 ) Other (5 ) (1 )
(17 ) 5 Adjusted net income allocated to common unitholders
$ 188 $ 243 $ 679 $ 533 Basic
weighted average common units outstanding 725 660 717 464 Effect of
dilutive securities: LTIP units (3) 1 2 1 2
Diluted weighted average common units outstanding 726
662 718 466 Diluted adjusted net income
per common unit (4) $ 0.26 $ 0.37 $ 0.94 $
1.14
_____________________________
(1) We calculate adjusted net income allocated to common
unitholders based on the distributions pertaining to the current
period’s net income (whether paid in cash or in-kind). After
adjusting for the appropriate period’s distributions, the remaining
undistributed earnings or excess distributions over earnings
(“undistributed loss”), if any, are allocated to the general
partner (for periods prior to the Simplification Transactions),
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.
The Simplification Transactions, which closed on November 15, 2016,
simplified our governance structure and permanently eliminated our
IDRs and the economic rights associated with our 2% general partner
interest. As such, beginning with the distribution pertaining to
the fourth quarter of 2016, our general partner is no longer
entitled to receive distributions from these interests. (2)
Certain of our non-GAAP financial measures may not be impacted by
each of the selected items impacting comparability. (3) Our
LTIP awards that contemplate the issuance of common units are
considered dilutive unless (i) vesting occurs only upon the
satisfaction of a performance condition and (ii) that performance
condition has yet to be satisfied. LTIP awards that are deemed to
be dilutive are reduced by a hypothetical unit repurchase based on
the remaining unamortized fair value, as prescribed by the treasury
stock method in guidance issued by the FASB. (4) The
possible conversion of our Series A preferred units was excluded
from the calculation of diluted adjusted net income per common unit
for the three and twelve months ended December 31, 2017 and 2016 as
the effect was antidilutive.
PLAINS GP HOLDINGS AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
(in millions, except per share data)
Three Months EndedDecember 31,
2017
Three Months EndedDecember 31, 2016
Consolidating Consolidating
PAA Adjustments (1) PAGP PAA
Adjustments (1) PAGP REVENUES $ 7,605 $
— $ 7,605 $ 5,952 $ — $ 5,952
COSTS AND EXPENSES
Purchases and related costs 6,746 — 6,746 5,234 — 5,234 Field
operating costs 307 — 307 289 — 289 General and administrative
expenses 66 1 67 68 1 69 Depreciation and amortization 225 —
225 143 — 143 Total costs and
expenses 7,344 1 7,345 5,734 1 5,735
OPERATING INCOME
261 (1 ) 260 218 (1 ) 217
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 90 — 90 61 — 61 Interest
expense, net (120 ) — (120 ) (127 ) (3 ) (130 ) Other expense, net
(26 ) — (26 ) (14 ) — (14 )
INCOME BEFORE
TAX 205 (1 ) 204 138 (4 ) 134 Current income tax expense (19 )
— (19 ) (41 ) — (41 ) Deferred income tax benefit/(expense) 5
(837 ) (832 ) 30 (1 ) 29
NET
INCOME/(LOSS) 191 (838 ) (647 ) 127 (5 ) 122 Net income
attributable to noncontrolling interests — (153 ) (153 ) (1
) (129 ) (130 )
NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP $ 191
$ (991 ) $ (800 ) $ 126 $ (134 ) $ (8 )
BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE $
(5.16 ) $ (0.08 )
BASIC AND DILUTED WEIGHTED AVERAGE
CLASS A SHARES OUTSTANDING 155 101
_____________________________
(1)
Represents the aggregate consolidating
adjustments necessary to produce consolidated financial statements
for PAGP.
PLAINS GP HOLDINGS AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
(in millions, except per share data)
Twelve Months EndedDecember 31, 2017 Twelve
Months EndedDecember 31, 2016
Consolidating Consolidating
PAA Adjustments (1) PAGP PAA
Adjustments (1) PAGP REVENUES $ 26,223
$ — $ 26,223 $ 20,182 $ — $ 20,182
COSTS AND EXPENSES
Purchases and related costs 22,985 — 22,985 17,233 — 17,233 Field
operating costs 1,183 — 1,183 1,182 — 1,182 General and
administrative expenses 276 4 280 279 3 282 Depreciation and
amortization 626 2 628 494 1 495
Total costs and expenses 25,070 6 25,076 19,188 4 19,192
OPERATING INCOME 1,153 (6 ) 1,147 994 (4 ) 990
OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated
entities 290 — 290 195 — 195 Interest expense, net (510 ) — (510 )
(467 ) (13 ) (480 ) Other income/(expense), net (31 ) — (31
) 33 — 33
INCOME BEFORE TAX 902
(6 ) 896 755 (17 ) 738 Current income tax expense (28 ) — (28 ) (85
) — (85 ) Deferred income tax benefit/(expense) (16 ) (893 ) (909 )
60 (53 ) 7
NET INCOME/(LOSS) 858 (899 )
(41 ) 730 (70 ) 660 Net income attributable to noncontrolling
interests (2 ) (688 ) (690 ) (4 ) (562 ) (566 )
NET
INCOME/(LOSS) ATTRIBUTABLE TO PAGP $ 856 $ (1,587 ) $
(731 ) $ 726 $ (632 ) $ 94
BASIC AND
DILUTED NET INCOME/(LOSS) PER CLASS A SHARE $ (5.03 ) $ 0.94
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES
OUTSTANDING 145 99
_____________________________
(1)
Represents the aggregate consolidating
adjustments necessary to produce consolidated financial statements
for PAGP.
PLAINS GP HOLDINGS AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATING BALANCE SHEET DATA
(in millions)
December 31, 2017 December 31, 2016
Consolidating Consolidating
PAA Adjustments (1) PAGP PAA
Adjustments (1) PAGP ASSETS Current
assets $ 4,000 $ 3 $ 4,003 $ 4,272 $ 3 $ 4,275 Property and
equipment, net 14,089 16 14,105 13,872 18 13,890 Goodwill 2,566 —
2,566 2,344 — 2,344 Investments in unconsolidated entities 2,756 —
2,756 2,343 — 2,343 Deferred tax asset — 1,386 1,386 — 1,876 1,876
Linefill and base gas 872 — 872 896 — 896 Long-term inventory 164 —
164 193 — 193 Other long-term assets, net 904 (3 ) 901
290 (4 ) 286
Total assets
$ 25,351 $ 1,402 $ 26,753 $ 24,210 $
1,893 $ 26,103
LIABILITIES AND PARTNERS'
CAPITAL Current liabilities $ 4,531 $ 2 $ 4,533 $ 4,664 $ 2 $
4,666 Senior notes, net of unamortized discounts and debt issuance
costs 8,933 — 8,933 9,874 — 9,874 Other long-term debt 250 — 250
250 — 250 Other long-term liabilities and deferred credits 679
— 679 606 — 606 Total
liabilities $ 14,393 $ 2 $ 14,395 $ 15,394 $ 2 $ 15,396
Partners' capital excluding noncontrolling interests 10,958 (9,263
) 1,695 8,759 (7,022 ) 1,737 Noncontrolling interests —
10,663 10,663 57 8,913 8,970 Total
partners' capital 10,958 1,400 12,358 8,816
1,891 10,707 Total liabilities and partners' capital
$ 25,351 $ 1,402 $ 26,753 $ 24,210 $
1,893 $ 26,103
_____________________________
(1)
Represents the aggregate consolidating
adjustments necessary to produce consolidated financial statements
for PAGP.
PLAINS GP HOLDINGS AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
COMPUTATION OF
BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A
SHARE
(in millions, except per share data)
Three Months EndedDecember
31,
Twelve Months EndedDecember
31,
2017 2016 2017 2016
Basic and Diluted Net Income/(Loss) per Class A Share Net
income/(loss) attributable to PAGP $ (800 ) $ (8 ) $ (731 ) $ 94
Basic and diluted weighted average Class A shares outstanding 155
101 145 99 Basic and diluted net income/(loss) per Class A
share (1) $ (5.16 ) $ (0.08 ) $ (5.03 ) $ 0.94
_____________________________
(1)
For the three and twelve months ended
December 31, 2017 and 2016, the possible exchange of any AAP units
and certain AAP Management Units would not have had a dilutive
effect on basic net income/(loss) per Class A share.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20180206006444/en/
Plains All American Pipeline, L.P. and Plains GP HoldingsRoy
Lamoreaux, 866-809-1291Vice President, Investor Relations &
CommunicationsorBrett Magill, 866-809-1291Manager, Investor
Relations
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