Timing of Earnings Call Changed to 5:00PM CT
This Evening, August 7, 2017
Plains All American Pipeline, L.P. (NYSE:PAA)
and Plains GP Holdings (NYSE:PAGP) today reported second-quarter
2017 results.
Plains All American Pipeline,
L.P.
Summary Financial
Information (unaudited)
(in millions, except per unit data)
Three Months Ended
Six Months Ended June 30,
% June 30, %
GAAP Results
2017 2016 Change 2017
2016 Change Net income attributable to PAA $ 188 $
101 86 % $ 632 $ 302 109 % Diluted net income/(loss) per common
unit $ 0.21 $ (0.20 ) 205 % $ 0.78 $ (0.13 ) 700 % Diluted weighted
average common units outstanding 727 398 83 % 710 398
78 % Distribution per common unit declared for the period $ 0.55
$ 0.70 (21.4 )%
Three Months Ended
Six Months Ended
June 30,
%
June 30,
%
Non-GAAP Results (1)
2017 2016 Change 2017 2016
Change Adjusted net income attributable to PAA $ 189 $ 136
39 % $ 414 $ 491 (16 )% Diluted adjusted net income/(loss) per
common unit $ 0.21 $ (0.12 ) 275 % $ 0.47 $ 0.33 42 % Adjusted
EBITDA (2) $ 451 $ 474 (5 )% $ 963 $ 1,107 (13 )%
(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.
(2)
Prior period amounts have been recast to
conform to certain changes made in the fourth quarter of 2016.
“This afternoon PAA reported second-quarter results in line with
the guidance provided in May,” stated Greg L. Armstrong, Chairman
and CEO of Plains All American Pipeline. “We continue to generate
attractive year-over-year growth in our fee-based segments, as
second quarter 2017 results for our Transportation and Facilities
segments increased an aggregate of 10% over last year’s comparative
quarterly results. Additionally, our outlook for our fee-based
segments, which comprise more than 90% of our consolidated Adjusted
EBITDA, remains solid. Based on completion of several projects and
step ups in commitment levels, we currently expect these two
fee-based segments to generate approximately 15% growth in
2018.
“Unfortunately, we continue to experience significant downward
pressure in our margin-based Supply and Logistics segment. As a
result, we updated our full-year 2017 Adjusted EBITDA guidance and
our 2018 preliminary forecast. The updated 2017 guidance reflects a
downward revision of $185 million, or 8%, primarily associated with
the Supply & Logistics segment. Our 2018 preliminary forecast
now includes a range with respect to our Supply & Logistics
segment, from $100 million to $300 million.
“The revisions to our updated 2017 Adjusted EBITDA guidance are
associated with our Supply and Logistics activities, primarily due
to a lack of visibility for crude oil and NGL arbitrage
opportunities that we have historically been able to capture with
our asset base and business model and margin erosion in our crude
oil and NGL supply activities.
”As we will discuss on our conference call, we are taking a
number of actions to ensure we are responsive to the market changes
experienced by our Supply and Logistics businesses. These actions
include changing the way we plan to manage our distribution and
taking other business, financial and balance sheet management
actions.” Armstrong noted that the conference call will be held
today, August 7, 2017, at 5:00 p.m. Central Time versus the
originally scheduled time of Tuesday, August 8, 2017 at 10:00 a.m.
Central Time.
Segment adjusted EBITDA for the second quarter
and first half of 2017 is presented below:
Summary of Selected Financial Data by
Segment (1) (unaudited)
(in millions)
Three Months Ended Three Months Ended
June 30, 2017
June 30, 2016 Supply and
Supply and Transportation Facilities
Logistics Transportation Facilities
Logistics Segment adjusted EBITDA $ 298 $ 180
$ (28 ) $ 274 $ 161 $ 39
Percentage change in
segment adjusted EBITDA versus 2016 period 9 %
12 % (172 )% Six Months
Ended Six Months Ended June 30, 2017 June 30,
2016 Supply and Supply and Transportation
Facilities Logistics Transportation
Facilities Logistics Segment adjusted EBITDA $ 571
$ 368 $ 23 $ 555 $ 327 $ 224
Percentage change in segment adjusted EBITDA versus 2016
period
3
% 13 % (90 )%
(1)
During the fourth quarter of 2016, we
modified our primary segment performance measure to segment
adjusted EBITDA from segment profit and also modified our
definition of adjusted EBITDA to exclude our proportionate share of
depreciation and amortization expense associated with equity method
investments. Prior-period segment amounts have been recast to
reflect these changes.
Second-quarter 2017 Transportation segment
adjusted EBITDA increased by 9% over comparable 2016 results. This
increase was primarily driven by increased volume on our Permian
Basin assets including contributions from the Alpha Crude Connector
gathering system that we acquired in February 2017 and
contributions from newly commissioned systems, partially offset by
the effects of non-core asset sales.
Second-quarter 2017 Facilities segment adjusted
EBITDA increased by 12% versus comparable 2016 results. This
increase was primarily due to contributions from the Canadian NGL
assets we acquired in August 2016, as well as higher fees at
certain of our NGL storage and fractionation facilities. These
increases were partially offset by lower U.S. rail terminal volumes
and revenues.
Second-quarter 2017 Supply and Logistics
segment adjusted EBITDA decreased by 172% relative to comparable
2016 results. This decrease was consistent with our expectations
and was due to continuing competition and margin compression
affecting our NGL and crude oil gathering and marketing
activities.
2017 Full-Year Guidance and 2018 Preliminary
Forecast
The table below presents our full-year 2017
financial and operating guidance and 2018 preliminary forecast:
Financial and
Operating Guidance (unaudited)
(in millions, except per barrel data)
Twelve Months Ended December 31,
2018 2015 2016 2017 (G)
Preliminary (1)
+ / -
+ / -
Segment Adjusted EBITDA Transportation $ 1,056 $ 1,141
$ 1,295 Facilities 588 667 705
Fee-Based
$
1,644
$ 1,808 $ 2,000 $2,350 Supply
and Logistics 568 359 75 100 - 300 Other income/(expense), net 1
2 —
Adjusted EBITDA (2)
$ 2,213 $ 2,169 $
2,075 $2,450 - $2,650 Interest expense, net
(3) (417 ) (451 ) (485 ) Maintenance capital (220 ) (186 ) (210 )
Current income tax expense (84 ) (85 ) (10 ) Other (18 ) (33 ) —
Implied DCF (2) $ 1,474
$ 1,414 $ 1,370
$1,725 - $1,925 Operating Data
Transportation Average daily volumes (MBbls/d) 4,453 4,637
5,295 Segment Adjusted EBITDA per barrel $ 0.65 $ 0.67 $ 0.67
Facilities Average capacity (MMBbls/Mo) 126 129 130
Segment Adjusted EBITDA per barrel $ 0.39 $ 0.43 $ 0.45
Supply and Logistics Average daily volumes (MBbls/d) 1,168
1,160 1,230 Segment Adjusted EBITDA per barrel $ 1.33 $ 0.85 $ 0.17
Expansion Capital $
2,170
$ 1,405 $ 950 Third-Quarter
Adjusted EBITDA as Percentage of Full Year 23%
21% 21% - 22% (G)
2017 Guidance forecasts are intended to be
+ / - amounts.
(1)
Represents 2018 preliminary forecast as
provided on May 24, 2017 at PAA 2017 Investor Day adjusted for
updated Supply and Logistics segment forecast.
(2)
See the section of this release entitled
“Non-GAAP Financial Measures and Selected Items Impacting
Comparability” and the Financial Data Reconciliations table
attached hereto for information regarding non-GAAP financial
measures and, for the historical 2015 and 2016 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.
(3)
Excludes certain non-cash items impacting
interest expense such as amortization of debt issuance costs and
terminated interest rate swaps.
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:
Q2 2017 Q1 2017 Q2
2016
Distribution per Class A share declared
for the period (1)
$ 0.55 $ 0.55 $ 0.62
Q2 2017 distribution percentage change
from prior periods
— % (11.3 )% (1)
A reverse split of PAGP’s Class A shares
was completed on November 15, 2016. The effect of the reverse split
has been retroactively applied to all per-share amounts
presented.
Conference Call
PAA and PAGP will hold a conference call at
5:00 p.m. CT on Monday, August 7, 2017 to discuss the following
items:
- PAA’s second-quarter 2017
performance;
- Financial and operating guidance for
the full year of 2017;
- Capitalization and liquidity; and
- PAA 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=1153900&tp_key=0fe580a410
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 and basic and diluted adjusted net income per
common 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 Condensed 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 Quarterly
Report on Form 10-Q.
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 Condensed 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 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 new or recently constructed 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, refined products 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
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; the impact of current and future laws, rulings, governmental
regulations, accounting standards and statements, and related
interpretations; 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 and refined products, 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, NGLs, natural gas and refined products. 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 approximately 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 Six Months Ended
June 30, June 30, 2017 2016
2017 2016 REVENUES $ 6,078 $ 4,950 $
12,745 $ 9,060
COSTS AND EXPENSES Purchases and
related costs 5,320 4,224 10,912 7,571 Field operating costs 304
303 593 603 General and administrative expenses 68 73 142 140
Depreciation and amortization 129 204 250
319 Total costs and expenses 5,821 4,804 11,897 8,633
OPERATING INCOME 257 146 848 427
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 68 40 121 87 Interest
expense, net (127 ) (114 ) (256 ) (227 ) Other income/(expense),
net 1 25 (4 ) 30
INCOME BEFORE TAX
199 97 709 317 Current income tax expense (1 ) (9 ) (11 ) (40 )
Deferred income tax benefit/(expense) (9 ) 14 (65 ) 27
NET INCOME
189 102 633 304 Net income attributable to noncontrolling interests
(1 ) (1 ) (1 ) (2 )
NET INCOME ATTRIBUTABLE TO PAA
$ 188 $ 101 $ 632 $ 302
NET
INCOME PER COMMON UNIT: Net income/(loss) allocated to common
unitholders — Basic $ 148 $ (81 ) $ 555 $ (53 ) Basic weighted
average common units outstanding 725 398 708 398 Basic net
income/(loss) per common unit $ 0.21 $ (0.20 ) $ 0.78
$ (0.13 ) Net income/(loss) allocated to common unitholders
— Diluted $ 148 $ (81 ) $ 555 $ (53 ) Diluted weighted average
common units outstanding 727 398 710 398 Diluted net income/(loss)
per common unit $ 0.21 $ (0.20 ) $ 0.78 $ (0.13 )
NON-GAAP ADJUSTED
RESULTS
(in millions, except per unit data)
Three Months Ended Six Months Ended June 30,
June 30, 2017 2016 2017 2016
Adjusted net income attributable to PAA $ 189 $ 136 $
414 $ 491 Diluted adjusted net income/(loss)
per common unit $ 0.21 $ (0.12 ) $ 0.47 $ 0.33
Adjusted EBITDA $ 451 $ 474 $ 963 $
1,107
PLAINS ALL AMERICAN PIPELINE, L.P.
AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATED BALANCE SHEET DATA
(in millions)
June 30, December 31,
2017 2016 ASSETS Current assets $ 3,528 $
4,272 Property and equipment, net 14,322 13,872 Goodwill 2,596
2,344 Investments in unconsolidated entities 2,626 2,343 Linefill
and base gas 894 896 Long-term inventory 117 193 Other long-term
assets, net 921 290 Total assets $ 25,004 $ 24,210
LIABILITIES AND PARTNERS' CAPITAL Current liabilities $
3,757 $ 4,664 Senior notes, net of unamortized discounts and debt
issuance costs 9,878 9,874 Other long-term debt 162 250 Other
long-term liabilities and deferred credits 706 606 Total
liabilities $ 14,503 $ 15,394 Partners' capital excluding
noncontrolling interests 10,444 8,759 Noncontrolling interests 57
57 Total partners' capital 10,501 8,816 Total liabilities and
partners' capital $ 25,004 $ 24,210
DEBT
CAPITALIZATION RATIOS
(in millions)
June 30,
December 31,
2017
2016
Short-term debt (1) $ 1,114 $ 1,715 Long-term debt 10,040
10,124 Total debt $ 11,154 $ 11,839
Long-term debt $ 10,040 $ 10,124 Partners' capital 10,501
8,816 Total book capitalization $ 20,541 $
18,940 Total book capitalization, including short-term debt
$ 21,655 $ 20,655 Long-term debt-to-total book
capitalization 49 % 53 % Total debt-to-total book capitalization,
including short-term debt 52 % 57 % (1)
As of June 30, 2017 and December 31, 2016,
short-term debt includes borrowings of approximately $1,099 million
and $1,303 million, respectively, for short-term hedged inventory
purchases and borrowings of approximately $12 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 Six Months Ended
June 30, June 30, 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) 2,761 2,178
2,614 2,112 South Texas / Eagle Ford (2) 349 274 330 294 Western
179 211 184 193 Rocky Mountain (2) 444 431 415 434 Gulf Coast 385
613 364 597 Central (2) 427 398 416 388 Canada 363 379 363 386
Crude oil pipelines 4,908 4,484 4,686 4,404 NGL pipelines 156 182
168 180 Tariff activities total volumes 5,064 4,666 4,854 4,584
Trucking volumes 99 115 106 110 Transportation segment total
volumes 5,163 4,781 4,960 4,694
Facilities segment
(average monthly volumes): Crude oil, refined products and NGL
terminalling and storage (average monthly capacity in millions of
barrels) 112 105 112 105 Rail load / unload volumes (average
volumes in thousands of barrels per day) 48 127 41 109 Natural gas
storage (average monthly working capacity in billions of cubic
feet) 97 97 97 97 NGL fractionation (average volumes in thousands
of barrels per day) 119 105 122 110 Facilities segment total
volumes (average monthly volumes in millions of barrels) (3) 134
128 133 128
Supply and Logistics segment (average daily
volumes in thousands of barrels per day): Crude oil lease
gathering purchases 940 885 929 899 NGL sales 210 176 280 242
Waterborne cargos — 5 3 6 Supply and Logistics segment total
volumes 1,150 1,066 1,212 1,147 (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) crude oil, refined products and NGL
terminalling and storage capacity; (ii) rail load and unload
volumes multiplied by the number of days in the period and divided
by the number of months in the period; (iii) 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 (iv) 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 Six Months Ended
June 30, June 30, 2017 2016
2017 2016 Basic Net Income per Common
Unit Net income attributable to PAA $ 188 $ 101 $ 632 $ 302
Distributions to Series A preferred units (35 ) (33 ) (69 ) (55 )
Distributions to general partner — (155 ) — (310 ) Other (5 ) 6
(8 ) 10 Net income/(loss) allocated to common
unitholders $ 148 $ (81 ) $ 555 $ (53 ) Basic
weighted average common units outstanding 725 398 708 398
Basic net income/(loss) per common unit $ 0.21 $ (0.20 ) $
0.78 $ (0.13 )
Diluted Net Income per Common
Unit Net income attributable to PAA $ 188 $ 101 $ 632 $ 302
Distributions to Series A preferred units (35 ) (33 ) (69 ) (55 )
Distributions to general partner — (155 ) — (310 ) Other (5 ) 6
(8 ) 10 Net income/(loss) allocated to common
unitholders $ 148 $ (81 ) $ 555 $ (53 ) Basic
weighted average common units outstanding 725 398 708 398 Effect of
dilutive securities: LTIP units (2) 2 — 2 —
Diluted weighted average common units outstanding 727
398 710 398 Diluted net income/(loss)
per common unit (3) $ 0.21 $ (0.20 ) $ 0.78 $ (0.13 )
(1)
We calculate net income/(loss) allocated
to common unitholders based on the distributions pertaining to the
current period’s net income. 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, 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. Such LTIP awards were excluded from
the calculation of diluted net loss per common unit for the three
and six months ended June 30, 2016 as the effect was
antidilutive.
(3)
The possible conversion of our Series A
preferred units was excluded from the calculation of diluted net
income/(loss) per common unit for the three and six months ended
June 30, 2017 and 2016 as the effect was antidilutive.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED
FINANCIAL DATA BY SEGMENT(1)
(in millions)
Three Months Ended Three Months Ended
June 30, 2017 June 30, 2016 Supply
and Supply and Transportation
Facilities Logistics Transportation
Facilities Logistics Revenues (2) $ 425 $ 289 $ 5,783
$ 403 $ 270 $ 4,652 Purchases and related costs (2) (21 ) (6 )
(5,708 ) (24 ) (6 ) (4,566 ) Field operating costs (2) (3) (155 )
(85 ) (65 ) (136 ) (88 ) (74 ) Equity-indexed compensation expense
- field operating costs (3 ) — — (5 ) (2 ) (1 ) Segment general and
administrative expenses (3) (4) (21 ) (16 ) (23 ) (21 ) (14 ) (24 )
Equity-indexed compensation expense - general and administrative (3
) (2 ) (3 ) (5 ) (4 ) (5 ) Equity earnings in unconsolidated
entities 68 — — 40 — — Adjustments: (5) Depreciation and
amortization of unconsolidated entities 4 — — 13 — — (Gains)/losses
from derivative activities net of inventory valuation adjustments —
(1 ) (12 ) — (2 ) 121 Long-term inventory costing adjustments — — 7
— — (67 ) Deficiencies under minimum volume commitments, net (14 )
— — 4 4 — Equity-indexed compensation expense 5 1 3 5 3 3 Net gain
on foreign currency revaluation — — (10 ) — — — Line 901 incident
12 — — — — — Significant acquisition-related expenses 1 —
— — — — Segment adjusted EBITDA
$ 298 $ 180 $ (28 ) $ 274 $ 161 $ 39
Maintenance capital $ 27 $ 39 $ 5
$ 23 $ 9 $ 3 (1)
During the fourth quarter of 2016, we
modified our primary segment performance measure to segment
adjusted EBITDA from segment profit. Segment adjusted EBITDA forms
the basis of our internal financial reporting and is the primary
measure used by our Chief Operating Decision Maker (“CODM”) in
assessing performance and allocating resources among our operating
segments. Prior period segment amounts have been recast to reflect
this change.
(2)
Includes intersegment amounts.
(3)
Field operating costs and Segment general
and administrative expenses exclude equity-indexed compensation
expense, which is presented separately in the table above.
(4)
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.
(5)
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
FINANCIAL DATA BY SEGMENT(1)
(in millions)
Six Months Ended Six Months Ended
June 30, 2017 June 30, 2016 Supply
and Supply and Transportation
Facilities Logistics Transportation
Facilities Logistics Revenues (2) $ 814 $ 582 $
12,184 $ 787 $ 535 $ 8,473 Purchases and related costs (2) (45 )
(17 ) (11,678 ) (45 ) (11 ) (8,243 ) Field operating costs (2) (3)
(293 ) (168 ) (131 ) (274 ) (173 ) (155 ) Equity-indexed
compensation expense - field operating costs (6 ) (1 ) (1 ) (5 ) (2
) (1 ) Segment general and administrative expenses (3) (4) (48 )
(34 ) (46 ) (44 ) (30 ) (48 ) Equity-indexed compensation expense -
general and administrative (5 ) (3 ) (6 ) (7 ) (4 ) (7 ) Equity
earnings in unconsolidated entities 121 — — 87 — —
Adjustments: (5) Depreciation and amortization of unconsolidated
entities 18 — — 25 — — (Gains)/losses from derivative activities
net of inventory valuation adjustments — 1 (303 ) — (1 ) 243
Long-term inventory costing adjustments — — 14 — — (44 )
Deficiencies under minimum volume commitments, net (9 ) 6 — 24 10 —
Equity-indexed compensation expense 6 2 4 7 3 5 Net (gain)/loss on
foreign currency revaluation — — (14 ) — — 1 Line 901 incident 12 —
— — — — Significant acquisition-related expenses 6 —
— — — — Segment adjusted EBITDA $ 571
$ 368 $ 23 $ 555 $ 327 $ 224
Maintenance capital $ 57 $ 66 $ 8
$ 57 $ 18 $ 6 (1)
During the fourth quarter of 2016, we
modified our primary segment performance measure to segment
adjusted EBITDA from segment profit. Segment adjusted EBITDA forms
the basis of our internal financial reporting and is the primary
measure used by our CODM in assessing performance and allocating
resources among our operating segments. Prior period segment
amounts have been recast to reflect this change.
(2)
Includes intersegment amounts.
(3)
Field operating costs and Segment general
and administrative expenses exclude equity-indexed compensation
expense, which is presented separately in the table above.
(4)
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.
(5)
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, except per unit data)
Three Months Ended Six Months Ended
June 30, June 30, 2017 2016
2017 2016 Selected Items Impacting
Comparability: (1) Gains/(losses) from derivative
activities net of inventory valuation adjustments (2) $ 15 $ (93 )
$ 300 $ (216 ) Long-term inventory costing adjustments (3) (7 ) 67
(14 ) 44 Deficiencies under minimum volume commitments, net (4) 14
(8 ) 3 (34 ) Equity-indexed compensation expense (5) (9 ) (11 ) (12
) (15 ) Net gain/(loss) on foreign currency revaluation (6) 8 (1 )
11 2 Line 901 incident (7) (12 ) — (12 ) — Significant
acquisition-related expenses (8) (1 ) — (6 ) —
Selected items impacting comparability - Adjusted EBITDA $ 8 $ (46
) $ 270 $ (219 ) Losses from derivative activities (2) (2 ) — (2 )
— Tax effect on selected items impacting comparability (7 ) 11
(50 ) 30 Selected items impacting comparability -
Adjusted net income attributable to PAA $ (1 ) $ (35 ) $ 218
$ (189 ) (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.
PLAINS ALL AMERICAN PIPELINE, L.P. AND
SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
NON-GAAP
RECONCILIATIONS
(in millions, except per unit data)
Three Months Ended Six Months Ended
June 30, June 30, 2017 2016
2017 2016 Net Income to Adjusted EBITDA and
Implied DCF Reconciliation Net Income $ 189 $ 102 $ 633 $ 304
Interest expense, net 127 114 256 227 Income tax (benefit)/expense
10 (5 ) 76 13 Depreciation and amortization 129 204 250 319
Depreciation and amortization of unconsolidated entities (1) 4 13
18 25 Selected items impacting comparability - Adjusted EBITDA (2)
(8 ) 46 (270 ) 219 Adjusted EBITDA $ 451 $ 474 $ 963
$ 1,107 Interest expense, net (3) (121 ) (110 ) (246 ) (219 )
Maintenance capital (71 ) (35 ) (131 ) (81 ) Current income tax
expense (1 ) (9 ) (11 ) (40 ) Adjusted equity earnings in
unconsolidated entities, net of distributions (4) 32 (5 ) 18 (11 )
Distributions to noncontrolling interests (5) (1 ) (1 ) (1 ) (2 )
Implied DCF (6) $ 289 $ 314 $ 592 $ 754
(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)
Includes cash distributions that pertain
to the current period’s net income, which are paid in the
subsequent period.
(6)
Including net costs recognized during the
periods related to the Line 901 incident that occurred in May 2015,
Implied DCF would have been $277 million and $580 million for the
three and six months ended June 30, 2017, respectively.
Three Months Ended Six Months
Ended June 30, June 30, 2017
2016 2017 2016 Net Income Per Common
Unit to Adjusted Net Income Per Common Unit Reconciliation
Basic net income/(loss) per common unit $ 0.21 $ (0.20 ) $ 0.78 $
(0.13 ) Selected items impacting comparability (1) — 0.08
(0.31 ) 0.46 Basic adjusted net income/(loss) per
common unit $ 0.21 $ (0.12 ) $ 0.47 $ 0.33 Diluted net
income/(loss) per common unit $ 0.21 $ (0.20 ) $ 0.78 $ (0.13 )
Selected items impacting comparability (1) — 0.08
(0.31 ) 0.46 Diluted adjusted net income/(loss) per common
unit $ 0.21 $ (0.12 ) $ 0.47 $ 0.33 (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)
NON-GAAP
RECONCILIATIONS (continued)
(in millions, except per unit data)
Twelve Months Ended December 31, 2016
2015 Net Income to Adjusted EBITDA and Implied DCF
Reconciliation Net Income $ 730 $ 906 Interest expense, net 467
432 Income tax expense 25 100 Depreciation and amortization 494 432
Depreciation and amortization of unconsolidated entities (1) 50 45
Selected items impacting comparability - Adjusted EBITDA 403
298 Adjusted EBITDA $ 2,169 $ 2,213 Interest expense, net
(2) (451 ) (417 ) Maintenance capital (186 ) (220 ) Current income
tax expense (85 ) (84 ) Adjusted equity earnings in unconsolidated
entities, net of distributions (3) (29 ) (14 ) Distributions to
noncontrolling interests (4) (4 ) (4 ) Implied DCF $ 1,414 $
1,474 (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)
Excludes certain non-cash items impacting
interest expense such as amortization of debt issuance costs and
terminated interest rate swaps.
(3)
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.
(4)
Includes cash distributions that pertain
to the current period’s net income, which are paid in the
subsequent period.
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 Six Months Ended
June 30, June 30, 2017 2016
2017 2016 Basic Adjusted Net Income per
Common Unit Net income attributable to PAA $ 188 $ 101 $ 632 $
302 Selected items impacting comparability - Adjusted net income
attributable to PAA (2) 1 35 (218 ) 189
Adjusted net income attributable to PAA 189 136 414 491
Distributions to Series A preferred units (35 ) (33 ) (69 ) (55 )
Distributions to general partner — (155 ) — (310 ) Other (5 ) 5
(8 ) 6 Adjusted net income/(loss) allocated to common
unitholders $ 149 $ (47 ) $ 337 $ 132
Basic weighted average common units outstanding 725 398 708 398
Basic adjusted net income/(loss) per common unit $ 0.21
$ (0.12 ) $ 0.47 $ 0.33
Diluted
Adjusted Net Income per Common Unit Net income attributable to
PAA $ 188 $ 101 $ 632 $ 302 Selected items impacting comparability
- Adjusted net income attributable to PAA (2) 1 35
(218 ) 189 Adjusted net income attributable to PAA 189 136
414 491 Distributions to Series A preferred units (35 ) (33 ) (69 )
(55 ) Distributions to general partner — (155 ) — (310 ) Other (5 )
5 (8 ) 6 Adjusted net income/(loss) allocated to
common unitholders $ 149 $ (47 ) $ 337 $ 132
Basic weighted average common units outstanding 725 398 708
398 Effect of dilutive securities: LTIP units (3) 2 —
2 1 Diluted weighted average common units outstanding
727 398 710 399 Diluted adjusted
net income/(loss) per common unit (4) $ 0.21 $ (0.12 ) $
0.47 $ 0.33 (1)
We calculate adjusted net income/(loss)
allocated to common unitholders based on the distributions
pertaining to the current period’s net income. 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, 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. Such LTIP awards were excluded from the calculation of
diluted adjusted net loss per common unit for the three months
ended June 30, 2016 as the effect was antidilutive.
(4)
The possible conversion of our Series A
preferred units was excluded from the calculation of diluted
adjusted net income/(loss) per common unit for the three and six
months ended June 30, 2017 and 2016 as the effect was
antidilutive.
PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS(1)
(in millions, except per share data)
Three Months Ended Three Months Ended
June 30, 2017 June 30, 2016
Consolidating Consolidating
PAA Adjustments (2) PAGP PAA
Adjustments (2) PAGP REVENUES $ 6,078 $
— $ 6,078 $ 4,950 $ — $ 4,950
COSTS AND EXPENSES
Purchases and related costs 5,320 — 5,320 4,224 — 4,224 Field
operating costs 304 — 304 303 — 303 General and administrative
expenses 68 1 69 73 — 73 Depreciation and amortization 129 —
129 204 1 205 Total costs and
expenses 5,821 1 5,822 4,804 1 4,805
OPERATING INCOME
257 (1 ) 256 146 (1 ) 145
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 68 — 68 40 — 40 Interest
expense, net (127 ) — (127 ) (114 ) (4 ) (118 ) Other income, net 1
— 1 25 — 25
INCOME BEFORE TAX 199 (1 ) 198 97 (5 ) 92 Current income tax
expense (1 ) — (1 ) (9 ) — (9 ) Deferred income tax
benefit/(expense) (9 ) (14 ) (23 ) 14 (15 ) (1 )
NET INCOME 189 (15 ) 174 102 (20 ) 82 Net income
attributable to noncontrolling interests (1 ) (149 ) (150 ) (1 )
(39 ) (40 )
NET INCOME ATTRIBUTABLE TO PAGP $ 188 $
(164 ) $ 24 $ 101 $ (59 ) $ 42
BASIC
NET INCOME PER CLASS A SHARE $ 0.16 $ 0.41
DILUTED NET INCOME PER CLASS A SHARE $ 0.16 $ 0.40
BASIC WEIGHTED AVERAGE CLASS A SHARES
OUTSTANDING 153 100
DILUTED WEIGHTED
AVERAGE CLASS A SHARES OUTSTANDING 153 234
(1)
A reverse split of PAGP’s Class A shares
was completed on November 15, 2016. The effect of the reverse split
has been retroactively applied to all share and per-share amounts
presented.
(2)
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(1)
(in millions, except per share data)
Six Months Ended Six Months
Ended June 30, 2017 June 30, 2016
Consolidating Consolidating
PAA Adjustments (2) PAGP PAA
Adjustments (2) PAGP REVENUES $ 12,745
$ — $ 12,745 $ 9,060 $ — $ 9,060
COSTS AND EXPENSES
Purchases and related costs 10,912 — 10,912 7,571 — 7,571 Field
operating costs 593 — 593 603 — 603 General and administrative
expenses 142 3 145 140 1 141 Depreciation and amortization 250
1 251 319 1 320 Total
costs and expenses 11,897 4 11,901 8,633 2 8,635
OPERATING INCOME 848 (4 ) 844 427 (2 ) 425
OTHER
INCOME/(EXPENSE) Equity earnings in unconsolidated entities 121
— 121 87 — 87 Interest expense, net (256 ) — (256 ) (227 ) (6 )
(233 ) Other income/(expense), net (4 ) — (4 ) 30 —
30
INCOME BEFORE TAX 709 (4 ) 705 317
(8 ) 309 Current income tax expense (11 ) — (11 ) (40 ) — (40 )
Deferred income tax benefit/(expense) (65 ) (54 ) (119 ) 27
(37 ) (10 )
NET INCOME 633 (58 ) 575 304 (45 ) 259
Net income attributable to noncontrolling interests (1 ) (509 )
(510 ) (2 ) (179 ) (181 )
NET INCOME ATTRIBUTABLE TO PAGP $
632 $ (567 ) $ 65 $ 302 $ (224 ) $ 78
BASIC NET INCOME PER CLASS A SHARE $ 0.47 $
0.80
DILUTED NET INCOME PER CLASS A SHARE $
0.47 $ 0.77
BASIC WEIGHTED AVERAGE CLASS A
SHARES OUTSTANDING 136 98
DILUTED
WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING 136 245
(1)
A reverse split of PAGP’s Class A shares
was completed on November 15, 2016. The effect of the reverse split
has been retroactively applied to all share and per-share amounts
presented.
(2)
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)
June 30, 2017 December 31, 2016
Consolidating Consolidating
PAA Adjustments (1) PAGP PAA
Adjustments (1) PAGP ASSETS Current
assets $ 3,528 $ 3 $ 3,531 $ 4,272 $ 3 $4,275 Property and
equipment, net 14,322 16 14,338 13,872 18 13,890 Goodwill 2,596 —
2,596 2,344 — 2,344 Investments in unconsolidated entities 2,626 —
2,626 2,343 — 2,343 Deferred tax asset — 2,214 2,214 — 1,876 1,876
Linefill and base gas 894 — 894 896 — 896 Long-term inventory 117 —
117 193 — 193 Other long-term assets, net 921 (2 ) 919
290 (4 ) 286 Total assets $ 25,004 $ 2,231
$ 27,235 $ 24,210 $ 1,893 $26,103
LIABILITIES AND PARTNERS' CAPITAL Current liabilities
$ 3,757 $ 2 $ 3,759 $ 4,664 $ 2 $4,666 Senior notes, net of
unamortized discounts and debt issuance costs 9,878 — 9,878 9,874 —
9,874 Other long-term debt 162 — 162 250 — 250 Other long-term
liabilities and deferred credits 706 — 706 606
— 606 Total liabilities $ 14,503 $ 2 $ 14,505 $
15,394 $ 2 $15,396 Partners' capital excluding
noncontrolling interests 10,444 (7,866 ) 2,578 8,759 (7,022 ) 1,737
Noncontrolling interests 57 10,095 10,152 57
8,913 8,970 Total partners' capital 10,501
2,229 12,730 8,816 1,891 10,707 Total
liabilities and partners' capital $ 25,004 $ 2,231 $
27,235 $ 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 PER CLASS A
SHARE(1)
(in millions, except per share data)
Three Months Ended Six Months Ended
June 30, June 30, 2017 2016
2017 2016 Basic Net Income per Class A
Share Net income attributable to PAGP $ 24 $ 42 $ 65 $ 78 Basic
weighted average Class A shares outstanding 153 100 136 98
Basic net income per Class A share $ 0.16 $ 0.41 $
0.47 $ 0.80
Diluted Net Income per Class A
Share Net income attributable to PAGP $ 24 $ 42 $ 65 $ 78
Incremental net income attributable to PAGP resulting from assumed
exchange of AAP units and AAP Management Units — 52 —
111 Net income attributable to PAGP including incremental
net income from assumed exchange of AAP units and AAP Management
Units $ 24 $ 94 $ 65 $ 189 Basic
weighted average Class A shares outstanding 153 100 136 98 Dilutive
shares resulting from assumed exchange of AAP units and AAP
Management Units — 134 — 147 Diluted weighted
average Class A shares outstanding 153 234 136
245 Diluted net income per Class A share (2) $ 0.16 $
0.40 $ 0.47 $ 0.77 (1)
A reverse split of PAGP’s Class A shares
was completed on November 15, 2016. The effect of the reverse split
has been retroactively applied to all share and per-share amounts
presented.
(2)
For the three and six months ended June
30, 2017, the possible exchange of any AAP units and certain AAP
Management Units would not have had a dilutive effect on basic net
income per Class A share.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20170807005954/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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