Market Overview

Plains All American Pipeline, L.P. and Plains GP Holdings Report Second-Quarter 2018 Results

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Plains All American Pipeline, L.P. (NYSE: PAA)
and Plains GP Holdings (NYSE: PAGP)
today reported second-quarter 2018 results.

Second-Quarter Highlights

  • Delivered 2Q18 financial and operating results ahead of expectations
  • Increased 2018 Adjusted EBITDA guidance
  • Continue to expect 14-15% fee-based Segment Adjusted EBITDA growth in
    2019
  • Increased 2018/2019 Capital Program ~$650 million to ~$2.6 billion
  • On target with leverage reduction plan

"We are pleased to report solid second-quarter results and increased
guidance for the full year," 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 within the first half of 2019, while maintaining
substantial distribution coverage underpinned by fee-based cash flow.
Additionally, strong Permian Basin fundamentals, combined with the
growth and execution of our capital program, provide visibility for
continued momentum for fee-based cash flow growth."

           

Plains All American Pipeline, L.P.

 

Summary Financial Information
(unaudited)

(in millions, except per unit data)

 

Three Months Ended
June 30,

% Six Months Ended
June 30,
%
GAAP Results 2018   2017 Change 2018   2017 Change
Net income attributable to PAA $ 100 $ 188 (47 )% $ 388 $ 632 (39 )%
Diluted net income per common unit $ 0.07 $ 0.21 (67 )% $ 0.39 $ 0.78 (50 )%
Diluted weighted average common units outstanding 727   727   % 727 710 2 %
Distribution per common unit declared for the period $ 0.30   $ 0.55   (45 )%
 
Three Months Ended
June 30,
% Six Months Ended
June 30,
%
Non-GAAP Results (1) 2018 2017 Change 2018 2017 Change
Adjusted net income attributable to PAA $ 324 $ 189 71 % $ 634 $ 414 53 %
Diluted adjusted net income per common unit $ 0.38 $ 0.21 81 % $ 0.73 $ 0.47 55 %
Adjusted EBITDA $ 506 $ 451 12 % $ 1,098 $ 963 14 %
Implied DCF per Common Unit $ 0.37 $ 0.40 (8 )% $ 0.98 $ 0.84 17 %

 

____________________

(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 second quarter and first half of 2018
and 2017 is presented below:

       

Summary of Selected Financial Data by
Segment
(unaudited)

(in millions)

 
Three Months Ended
June 30, 2018
Three Months Ended
June 30, 2017
Transportation   Facilities  

Supply and
Logistics

Transportation   Facilities  

Supply and
Logistics

Segment Adjusted EBITDA $ 360   $ 171   $ (26 ) $ 298   $ 180   $ (28 )
Percentage change in Segment Adjusted EBITDA versus 2017 period 21 % (5 )% 7 %
Percentage change in Segment Adjusted EBITDA versus 2017
further adjusted for impact of divested assets
27 % 3 % N/A  
 
Six Months Ended
June 30, 2018
Six Months Ended
June 30, 2017
Transportation Facilities Supply and Logistics Transportation Facilities Supply and Logistics
Segment Adjusted EBITDA $ 695   $ 357   $ 45   $ 571   $ 368   $ 23  
Percentage change in Segment Adjusted EBITDA versus 2017 period 22 % (3 )% 96 %
Percentage change in Segment Adjusted EBITDA versus 2017
further adjusted for impact of divested assets
26 % 5 % N/A  
 

Second-quarter 2018 Transportation Segment Adjusted EBITDA increased by
21% over comparable 2017 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. Second-quarter 2018 also benefited
from Diamond pipeline being placed into service in late 2017.
Second-quarter 2018 results also were impacted by the sale of assets in
the Rocky Mountain and Central regions.

Second-quarter 2018 Facilities Segment Adjusted EBITDA decreased by 5%
versus comparable 2017 results, primarily due to the impact of asset
sales. This was partially offset by increased revenue from capacity
expansions and increased throughput at our Cushing terminal.

Second-quarter 2018 Supply and Logistics Segment Adjusted EBITDA
increased versus comparable 2017 results due to improved NGL margins and
crude oil arbitrage opportunities, partially offset by the absence of
contango market conditions experienced in 2017.

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 barrel data)

 
Twelve Months Ended December 31,
2016   2017   2018 (G)
+ / -
Segment Adjusted EBITDA
Transportation $ 1,141 $ 1,287 $ 1,535
Facilities 667   734   690  
Fee-Based $ 1,808 $ 2,021 $ 2,225
Supply and Logistics 359 60 175
Other income/(expense), net 2   1    
Adjusted EBITDA (1) $ 2,169   $ 2,082   $ 2,400  
Interest expense, net (2) (451 ) (483 ) (420 )
Maintenance capital (186 ) (247 ) (225 )
Current income tax expense (85 ) (28 ) (45 )
Other (33 ) (12 ) 5  
Implied DCF (1) $ 1,414 $ 1,312 $ 1,715
Preferred unit distributions paid (3) (5 ) (160 )
General partner cash distributions (565 )    
Implied DCF Available to Common Unitholders $ 849   $ 1,307   $ 1,555  
 
Implied DCF per Common Unit (1) $ 1.83 $ 1.82 $ 2.14
Implied DCF per Common Unit and Common Equivalent Unit (1) $ 1.63 $ 1.67 $ 2.09
 
Distributions per Common Unit (4) $ 2.65 $ 1.95 $ 1.20
Common Unit Distribution Coverage Ratio 0.87x 0.94x 1.79x
 
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 $ 0.46
 
Supply and Logistics
Average daily volumes (MBbls/d) 1,153 1,219 1,275
Segment Adjusted EBITDA per barrel $ 0.85 $ 0.13 $ 0.38
 
Expansion Capital $ 1,405 $ 1,135 $ 1,950
 
Third-Quarter Adjusted EBITDA as Percentage of Full Year 21% 23% 23%
 

____________________

(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 and for the February 2018 quarterly distribution.
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:

    Q2 2018   Q1 2018   Q2 2017
Distribution per Class A share declared for the period $ 0.30 $ 0.30   $ 0.55  
Q2 2018 distribution percentage change from prior periods % (45 )%
 

Conference Call

PAA and PAGP will hold a joint conference call at 4:00 p.m. CT on
Tuesday, August 7, 2018 to discuss the following items:

  1. PAA's second-quarter 2018 performance;
  2. Financial and operating guidance for the full year of 2018;
  3. Capitalization and liquidity; and
  4. 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=1199816&tp_key=608fb57b8d

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. A transcript will
also be available after the call at the above referenced website.

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 measures 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 actual or expected volume of crude
oil and NGL shipped, processed, purchased, stored, fractionated and/or
gathered at or through the use of our assets, whether due to declines in
production from existing oil and gas reserves, reduced demand, failure
to develop or slowdown in the development of additional oil and gas
reserves, whether from reduced cash flow to fund drilling or the
inability to access capital, or other factors; the effects of
competition; market distortions caused by over-commitments to
infrastructure projects, which impacts volumes, margins, returns and
overall earnings; unanticipated changes in crude oil and NGL market
structure, grade differentials and volatility (or lack thereof);
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; shortages or
cost increases of supplies, materials or labor; the impact of current
and future laws, rulings, governmental regulations, accounting standards
and statements, and related interpretations; the failure to consummate,
or significant delay in consummating, sales of assets or interests as a
part of our strategic divestiture program; tightened capital markets or
other factors that increase our cost of capital or limit our ability to
obtain debt or equity financing on satisfactory terms to fund additional
acquisitions, expansion projects, working capital requirements and the
repayment or refinancing of indebtedness; the availability of, and our
ability to consummate, acquisition or combination opportunities; the
successful integration and future performance of acquired assets or
businesses and the risks associated with operating in lines of business
that are distinct and separate from our historical operations; the
currency exchange rate of the Canadian dollar; continued
creditworthiness of, and performance by, our counterparties, including
financial institutions and trading companies with which we do business;
inability to recognize current revenue attributable to deficiency
payments received from customers who fail to ship or move more than
minimum contracted volumes until the related credits expire or are used;
non-utilization of our assets and facilities; increased costs, or lack
of availability, of insurance; weather interference with business
operations or project construction, including the impact of extreme
weather events or conditions; the effectiveness of our risk management
activities; fluctuations in the debt and equity markets, including the
price of our units at the time of vesting under our long-term incentive
plans; risks related to the development and operation of our assets,
including our ability to satisfy our contractual obligations to our
customers; factors affecting demand for natural gas and natural gas
storage services and rates; general economic, market or business
conditions and the amplification of other risks caused by volatile
financial markets, capital constraints and pervasive liquidity concerns;
and other factors and uncertainties inherent in the transportation,
storage, terminalling and marketing of crude oil, as well as in the
storage of natural gas and the processing, transportation,
fractionation, storage and marketing of natural gas liquids 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 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 more than 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
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
REVENUES $ 8,080 $ 6,078 $ 16,478 $ 12,745
 
COSTS AND EXPENSES
Purchases and related costs 7,551 5,320 15,070 10,912
Field operating costs 312 304 605 593
General and administrative expenses 80 68 159 142
Depreciation and amortization 49   129   175   250  
Total costs and expenses 7,992 5,821 16,009 11,897
 
OPERATING INCOME 88 257 469 848
 
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 96 68 171 121
Interest expense, net (111 ) (127 ) (217 ) (256 )
Other income/(expense), net 11   1   10   (4 )
 
INCOME BEFORE TAX 84 199 433 709
Current income tax expense (7 ) (1 ) (20 ) (11 )
Deferred income tax benefit/(expense) 23 (9 ) (25 ) (65 )
 
NET INCOME 100 189 388 633
Net income attributable to noncontrolling interests   (1 )   (1 )
NET INCOME ATTRIBUTABLE TO PAA $ 100   $ 188   $ 388   $ 632  
 
NET INCOME PER COMMON UNIT:
Net income allocated to common unitholders — Basic $ 50 $ 148 $ 286 $ 555
Basic weighted average common units outstanding 725 725 725 708
Basic net income per common unit $ 0.07   $ 0.21   $ 0.39   $ 0.78  
 
Net income allocated to common unitholders — Diluted $ 50 $ 148 $ 286 $ 555
Diluted weighted average common units outstanding 727 727 727 710
Diluted net income per common unit $ 0.07   $ 0.21   $ 0.39   $ 0.78  
 

NON-GAAP ADJUSTED RESULTS

(in millions, except per unit data)

 
Three Months Ended
June 30,
Six Months Ended
June 30,
2018 2017 2018 2017
Adjusted net income attributable to PAA $ 324   $ 189   $ 634   $ 414  
 
Diluted adjusted net income per common unit $ 0.38   $ 0.21   $ 0.73   $ 0.47  
 
Adjusted EBITDA $ 506   $ 451   $ 1,098   $ 963  
 
   

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

 
June 30,
2018
December 31,
2017
ASSETS
Current assets $ 3,852 $ 4,000
Property and equipment, net 14,257 14,089
Goodwill 2,535 2,566
Investments in unconsolidated entities 3,116 2,756
Linefill and base gas 866 872
Long-term inventory 169 164
Other long-term assets, net 904   904
Total assets $ 25,699   $ 25,351
 
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities $ 5,122 $ 4,531
Senior notes, net of unamortized discounts and debt issuance costs 8,937 8,933
Other long-term debt 29 250
Other long-term liabilities and deferred credits 787   679
Total liabilities 14,875 14,393
 
Partners' capital 10,824   10,958
Total liabilities and partners' capital $ 25,699   $ 25,351
 

DEBT CAPITALIZATION RATIOS

(in millions)

 
June 30,
2018
December 31,
2017
Short-term debt (1) $ 943 $ 737
Long-term debt 8,966   9,183  
Total debt $ 9,909   $ 9,920  
 
Long-term debt $ 8,966 $ 9,183
Partners' capital 10,824   10,958  
Total book capitalization $ 19,790   $ 20,141  
Total book capitalization, including short-term debt $ 20,733   $ 20,878  
 
Long-term debt-to-total book capitalization 45 % 46 %
Total debt-to-total book capitalization, including short-term debt 48 % 48 %
 

____________________

(1)  

As of June 30, 2018 and December 31, 2017, short-term debt
includes borrowings of approximately $515 million and $523
million, respectively, for short-term hedged inventory purchases
and borrowings of approximately $426 million and $212 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
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Transportation segment (average daily volumes in thousands of
barrels per day):
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (2) 3,734 2,761 3,489 2,614
South Texas / Eagle Ford (2) 434 349 428 330
Central (2) 448 427 445 416
Gulf Coast 170 385 187 364
Rocky Mountain (2) 270 444 263 415
Western 181 179 177 184
Canada 298   363   308   363
Crude oil pipelines 5,535 4,908 5,297 4,686
NGL pipelines 171   156   172   168
Tariff activities total volumes 5,706 5,064 5,469 4,854
Trucking volumes 91   99   95   106
Transportation segment total volumes 5,797   5,163   5,564   4,960
 
Facilities segment (average monthly volumes):
Liquids storage (average monthly capacity in millions of barrels) 109   112   109   112
Natural gas storage (average monthly working capacity in billions of
cubic feet)
65   97   66   97
NGL fractionation (average volumes in thousands of barrels per day) 132   119   135   122
Facilities segment total volumes (average monthly volumes in
millions of barrels) (3)
124   132   124   132
 
Supply and Logistics segment (average daily volumes in thousands
of barrels per day):
Crude oil lease gathering purchases 1,028 940 1,030 929
NGL sales 174   210   266   280
Supply and Logistics segment total volumes 1,202   1,150   1,296   1,209
 

____________________

(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
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Basic Net Income per Common Unit
Net income attributable to PAA $ 100 $ 188 $ 388 $ 632
Distributions to Series A preferred unitholders (37 ) (35 ) (74 ) (69 )
Distributions to Series B preferred unitholders (12 ) (25 )
Other (1 ) (5 ) (3 ) (8 )
Net income allocated to common unitholders $ 50   $ 148   $ 286   $ 555  
 
Basic weighted average common units outstanding 725 725 725 708
 
Basic net income per common unit $ 0.07   $ 0.21   $ 0.39   $ 0.78  
 
Diluted Net Income per Common Unit
Net income attributable to PAA $ 100 $ 188 $ 388 $ 632
Distributions to Series A preferred unitholders (37 ) (35 ) (74 ) (69 )
Distributions to Series B preferred unitholders (12 ) (25 )
Other (1 ) (5 ) (3 ) (8 )
Net income allocated to common unitholders $ 50   $ 148   $ 286   $ 555  
 
Basic weighted average common units outstanding 725 725 725 708
Effect of dilutive securities:
Equity-indexed compensation plan awards (2) 2   2   2   2  
Diluted weighted average common units outstanding 727   727   727   710  
 
Diluted net income per common unit (3) $ 0.07   $ 0.21   $ 0.39   $ 0.78  
 

____________________

(1)   We calculate net income allocated to common unitholders based
on the distributions pertaining to the current period's net income
(whether paid in cash or in-kind). After adjusting for the
appropriate period's distributions, the remaining undistributed
earnings or excess distributions over earnings, if any, are
allocated to common unitholders and participating securities in
accordance with the contractual terms of our partnership agreement
in effect for the period and as further prescribed under the
two-class method.
 
(2) Our Long-term Incentive Plan ("LTIP") awards that contemplate
the issuance of common units and certain AAP Management Units that
contemplate the issuance of common units to AAP when such AAP
Management Units become earned are considered dilutive unless (i)
they become vested or earned only upon the satisfaction of a
performance condition and (ii) that performance condition has yet to
be satisfied. LTIP awards and AAP Management Units that are deemed
to be dilutive are reduced by a hypothetical common unit repurchase
based on the remaining unamortized fair value, as prescribed by the
treasury stock method in guidance issued by the FASB.
 
(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 six months ended June 30, 2018 and 2017 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 Ended
June 30, 2018
Three Months Ended
June 30, 2017
Transportation   Facilities  

Supply and
Logistics

Transportation   Facilities  

Supply and
Logistics

Revenues (1) $ 475 $ 284 $ 7,781 $ 425 $ 289 $ 5,783
Purchases and related costs (1) (46 ) (3 ) (7,959 ) (21 ) (6 ) (5,708 )
Field operating costs (1) (2) (157 ) (92 ) (66 ) (158 ) (85 ) (65 )
Segment general and administrative expenses (2) (3) (30 ) (21 ) (29 ) (24 ) (18 ) (26 )
Equity earnings in unconsolidated entities 96 68
 
Adjustments: (4)
Depreciation and amortization of unconsolidated entities 14 4
(Gains)/losses from derivative activities net of inventory valuation
adjustments
(1 ) 241 (1 ) (12 )
Long-term inventory costing adjustments 5 7
Deficiencies under minimum volume commitments, net 1 2 (14 )
Equity-indexed compensation expense 7 2 3 5 1 3
Net gain on foreign currency revaluation (2 ) (10 )
Line 901 incident 12
Significant acquisition-related expenses       1      
Segment Adjusted EBITDA $ 360   $ 171   $ (26 ) $ 298   $ 180   $ (28 )
 
Maintenance capital $ 32   $ 26   $ 5   $ 27   $ 39   $ 5  
 

____________________

(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)

 
 
Six Months Ended
June 30, 2018
Six Months Ended
June 30, 2017
Transportation   Facilities  

Supply and
Logistics

Transportation   Facilities  

Supply and
Logistics

Revenues (1) $ 929 $ 576 $ 15,893 $ 814 $ 582 $ 12,184
Purchases and related costs (1) (92 ) (8 ) (15,884 ) (45 ) (17 ) (11,678 )
Field operating costs (1) (2) (304 ) (176 ) (131 ) (299 ) (169 ) (132 )
Segment general and administrative expenses (2) (3) (58 ) (42 ) (59 ) (53 ) (37 ) (52 )
Equity earnings in unconsolidated entities 171 121
 
Adjustments: (4)
Depreciation and amortization of unconsolidated entities 29 18
(Gains)/losses from derivative activities net of inventory valuation
adjustments
(1 ) (2 ) 219 1 (303 )
Long-term inventory costing adjustments (7 ) 14
Deficiencies under minimum volume commitments, net 9 4 (9 ) 6
Equity-indexed compensation expense 12 5 6 6 2 4
Net (gain)/loss on foreign currency revaluation 8 (14 )
Line 901 incident 12
Significant acquisition-related expenses       6      
Segment Adjusted EBITDA $ 695   $ 357   $ 45   $ 571   $ 368   $ 23  
 
Maintenance capital $ 61   $ 41   $ 6   $ 57   $ 66   $ 8  
 

____________________

(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
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Selected Items Impacting Comparability: (1)
Gains/(losses) from derivative activities net of inventory valuation
adjustments (2)
$ (232 ) $ 15 $ (211 ) $ 300
Long-term inventory costing adjustments (3) (5 ) (7 ) 7 (14 )
Deficiencies under minimum volume commitments, net (4) (3 ) 14 (13 ) 3
Equity-indexed compensation expense (5) (12 ) (9 ) (23 ) (12 )
Net gain/(loss) on foreign currency revaluation (6) 4 8 (4 ) 11
Line 901 incident (7) (12 ) (12 )
Significant acquisition-related expenses (8)   (1 )   (6 )
Selected items impacting comparability - Adjusted EBITDA $ (248 ) $ 8 $ (244 ) $ 270
Gains/(losses) from derivative activities (2) (2 ) 3 (2 )
Tax effect on selected items impacting comparability 24   (7 ) (5 ) (50 )
Selected items impacting comparability - Adjusted net income
attributable to PAA
$ (224 ) $ (1 ) $ (246 ) $ 218  
 

____________________

(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 and ratio data)

 
 
Three Months Ended
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income $ 100 $ 189 $ 388 $ 633
Interest expense, net 111 127 217 256
Income tax (benefit)/expense (16 ) 10 45 76
Depreciation and amortization 49 129 175 250
Depreciation and amortization of unconsolidated entities (1) 14 4 29 18
Selected items impacting comparability - Adjusted EBITDA (2) 248   (8 ) 244   (270 )
Adjusted EBITDA $ 506 $ 451 $ 1,098 $ 963
Interest expense, net (3) (107 ) (121 ) (212 ) (246 )
Maintenance capital (63 ) (71 ) (108 ) (131 )
Current income tax expense (7 ) (1 ) (20 ) (11 )
Adjusted equity earnings in unconsolidated entities, net of
distributions (4)
1 32 15 18
Distributions to noncontrolling interests (5)       (1 )
Implied DCF $ 330 $ 290 $ 773 $ 592
Preferred unit distributions (6) (62 )   (62 )  
Implied DCF Available to Common Unitholders $ 268   $ 290   $ 711   $ 592  
 
Implied DCF per Common Unit (7) $ 0.37 $ 0.40 $ 0.98 $ 0.84
Implied DCF per Common Unit and Common Equivalent Unit (8) $ 0.38 $ 0.37 $ 0.94 $ 0.76
 
Cash Distribution Paid per Common Unit $ 0.30 $ 0.55 $ 0.60 $ 1.10
Common Unit Cash Distributions (5) $ 218 $ 399 $ 435 $ 770
Common Unit Distribution Coverage Ratio 1.23x 0.73x 1.63x 0.77x
 
Implied DCF Excess / (Shortage) $ 50 $ (109 ) $ 276 $ (178 )
 

____________________

(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) Cash distributions paid during the period presented.
 
(6) Cash distributions paid to our preferred unitholders during the
period presented. The current $0.5250 quarterly ($2.10 annualized)
per unit distribution requirement of our Series A preferred units
was paid-in-kind for each quarterly distribution from their issuance
through February 2018. Distributions on our Series A preferred units
were paid in cash beginning with the May 2018 quarterly
distribution. The current $61.25 per unit annual distribution
requirement of our Series B preferred units, which were issued in
October 2017, is payable semi-annually in arrears on May 15 and
November 15.
 
(7) Implied DCF Available to Common Unitholders for the period
divided by the weighted average common units outstanding for the
period of 725 million, 725 million, 725 million, and 708 million,
respectively.
 
(8) 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 796 million, 791
million, 796 million, and 774 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.
 
   

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

NON-GAAP RECONCILIATIONS (continued)

(in millions, except per unit data)

 
Three Months Ended
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Net Income Per Common Unit to Implied DCF Per Common Unit and
Common Equivalent Unit Reconciliation
Basic net income per common unit $ 0.07 $ 0.21 $ 0.39 $ 0.78
Reconciling items per common unit (1) (2) 0.30   0.19   0.59   0.06  
Implied DCF per common unit $ 0.37   $ 0.40   $ 0.98   $ 0.84  
 
Basic net income per common unit $ 0.07 $ 0.21 $ 0.39 $ 0.78
Reconciling items per common unit and common equivalent unit (1)
(3)
0.31   0.16   0.55   (0.02 )
Implied DCF per common unit and common equivalent unit $ 0.38   $ 0.37   $ 0.94   $ 0.76  
 

____________________

(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, 725 million, 725 million and 708 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 approximately 71 million, 66
million, 71 million and 66 million, respectively.

 
   
Three Months Ended
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Net Income Per Common Unit to Adjusted Net Income Per Common Unit
Reconciliation
Basic net income per common unit $ 0.07 $ 0.21 $ 0.39 $ 0.78
Selected items impacting comparability per common unit (1) 0.31     0.34   (0.31 )
Basic adjusted net income per common unit $ 0.38   $ 0.21   $ 0.73   $ 0.47  
 
Diluted net income per common unit $ 0.07 $ 0.21 $ 0.39 $ 0.78
Selected items impacting comparability per common unit (1) 0.31     0.34   (0.31 )
Diluted adjusted net income per common unit $ 0.38   $ 0.21   $ 0.73   $ 0.47  
 

____________________

(1)  

See the "Selected Items Impacting Comparability" and the
"Computation of Basic and Diluted Adjusted Net Income Per Common
Unit" tables for additional information.

 
   
Three Months Ended
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Fee-based Segment Adjusted EBITDA to Adjusted EBITDA
Reconciliation
Transportation Segment Adjusted EBITDA $ 360 $ 298 $ 695 $ 571
Facilities Segment Adjusted EBITDA 171   180   357   368
Fee-based Segment Adjusted EBITDA $ 531 $ 478 $ 1,052 $ 939
Supply and Logistics Segment Adjusted EBITDA (26 ) (28 ) 45 23
Adjusted other income/(expense), net (1) 1   1   1   1
Adjusted EBITDA (2) $ 506   $ 451   $ 1,098   $ 963
 

____________________

(1)  

Represents Other income/(expense), net adjusted for selected
items impacting comparability of $(10) million, less than $1
million, $(9) million and $5 million for the three and six months
ended June 30, 2018 and 2017, respectively. See the "Selected
Items Impacting Comparability" table for additional information.

 
(2)

See the "Net Income to Adjusted EBITDA and Implied DCF
Reconciliation" table for reconciliation to net income.

 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

NON-GAAP RECONCILIATIONS (continued)

(in millions, except per unit and ratio data)

 
Twelve Months Ended
December 31,
2017   2016
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income $ 858 $ 730
Interest expense, net 510 467
Income tax expense 44 25
Depreciation and amortization 626 494
Depreciation and amortization of unconsolidated entities (1) 45 50
Selected items impacting comparability - Adjusted EBITDA (1 ) 403  

Adjusted EBITDA

$ 2,082   $ 2,169  
Interest expense, net (2) (483 ) (451 )
Maintenance capital (247 ) (186 )
Current income tax expense (28 ) (85 )
Adjusted equity earnings in unconsolidated entities, net of
distributions (3)
(10 ) (29 )
Distributions to noncontrolling interests (2 ) (4 )
Implied DCF $ 1,312 $ 1,414
Preferred unit distributions (4) (5 )
General partner cash distributions (5)   (565 )
Implied DCF Available to Common Unitholders $ 1,307   $ 849  
 
Implied DCF per Common Unit (6) $ 1.82 $ 1.83
Implied DCF per Common Unit and Common Equivalent Unit (7) $ 1.67 $ 1.63
 
Cash Distribution Paid per Common Unit $ 1.95 $ 2.65
Common Unit Cash Distributions (8) $ 1,386 $ 1,627
Common Unit Distribution Coverage Ratio 0.94x 0.87x
 
Implied DCF Excess / (Shortage) $ (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) 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) 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.
 
(5) 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.
 
(6) Implied DCF Available to Common Unitholders for the period
divided by the weighted average common units outstanding for the
periods of 717 million and 464 million, respectively.
 
(7) 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 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.
 
(8) Cash distributions paid during the period presented. For the
twelve months ended December 31, 2016, includes $565 million 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)

(in millions, except per unit data)

 
Twelve Months Ended
December 31,
2017   2016
Net Income Per Common Unit to Implied DCF Per Common Unit and
Common Equivalent Unit Reconciliation
Basic net income per common unit $ 0.96 $ 0.43
Reconciling items per common unit (1) (2) 0.86   1.40
Implied DCF per common unit $ 1.82   $ 1.83
 
Basic net income per common unit $ 0.96 $ 0.43
Reconciling items per common unit and common equivalent unit (1)
(3)
0.71   1.20
Implied DCF per common unit and common equivalent unit $ 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 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 67 million and 58 million,
respectively.
 
 

Reconciliation of Segment Adjusted EBITDA to Segment Adjusted
EBITDA further adjusted for impact of divested assets

 

  Three Months Ended
June 30, 2018
    Three Months Ended
June 30, 2017
Transportation   Facilities  

Supply and
Logistics

Transportation

  Facilities  

Supply and
Logistics

Segment Adjusted EBITDA $ 360 $ 171 $ (26 ) $ 298 $ 180 $ (28 )
Impact of divested assets (1) (2 )     (16 ) (14 )  
Segment Adjusted EBITDA further adjusted for impact of divested
assets
$ 358   $ 171   $ (26 ) $ 282   $ 166   $ (28 )
  Six Months Ended
June 30, 2018
    Six Months Ended
June 30, 2017
Transportation   Facilities  

Supply and
Logistics

Transportation   Facilities  

Supply and
Logistics

Segment Adjusted EBITDA $ 695 $ 357 $ 45 $ 571 $ 368 $

23

 

Impact of divested assets (1) (6 ) (2 )   (26 ) (29 )  
Segment Adjusted EBITDA further adjusted for impact of divested
assets
$ 689   $ 355   $ 45   $ 545   $ 339   $ 23  
 

____________________

(1)   Estimated impact of divestitures completed during 2017 and the
first six months of 2018, assuming an effective date of 1/1/17.
Divested assets include certain pipelines in the Rocky Mountain and
Central regions that were previously reported in our Transportation
segment, and certain Bay Area, California terminal assets, a natural
gas storage facility and a natural gas processing facility that were
previously reported in our Facilities segment.
 
   

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
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Basic Adjusted Net Income per Common Unit
Net income attributable to PAA $ 100 $ 188 $ 388 $ 632
Selected items impacting comparability - Adjusted net income
attributable to PAA (2)
224   1   246   (218 )
Adjusted net income attributable to PAA $ 324 $ 189 $ 634 $ 414
Distributions to Series A preferred unitholders (37 ) (35 ) (74 ) (69 )
Distributions to Series B preferred unitholders (12 ) (25 )
Other (1 ) (5 ) (3 ) (8 )
Adjusted net income allocated to common unitholders $ 274   $ 149   $ 532   $ 337  
 
Basic weighted average common units outstanding 725 725 725 708
 
Basic adjusted net income per common unit $ 0.38   $ 0.21   $ 0.73   $ 0.47  
 
Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA $ 100 $ 188 $ 388 $ 632
Selected items impacting comparability - Adjusted net income
attributable to PAA (2)
224   1   246   (218 )
Adjusted net income attributable to PAA $ 324 $ 189 $ 634 $ 414
Distributions to Series A preferred unitholders (37 ) (35 ) (74 ) (69 )
Distributions to Series B preferred unitholders (12 ) (25 )
Other (1 ) (5 ) (3 ) (8 )
Adjusted net income allocated to common unitholders $ 274   $ 149   $ 532   $ 337  
 
Basic weighted average common units outstanding 725 725 725 708
Effect of dilutive securities:
Equity-indexed compensation plan awards (3) 2   2   2   2  
Diluted weighted average common units outstanding 727   727   727   710  
 
Diluted adjusted net income per common unit (4) $ 0.38   $ 0.21   $ 0.73   $ 0.47  
 

____________________

(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, if
any, are allocated to the 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.
 
(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
and certain AAP Management Units that contemplate the issuance of
common units to AAP when such AAP Management Units become earned are
considered dilutive unless (i) they become vested or earned only
upon the satisfaction of a performance condition and (ii) that
performance condition has yet to be satisfied. LTIP awards and AAP
Management Units that are deemed to be dilutive are reduced by a
hypothetical common unit repurchase based on the remaining
unamortized fair value, as prescribed by the treasury stock method
in guidance issued by the FASB.
 
(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 six months ended June 30, 2018 and
2017 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 Ended
June 30, 2018
Three Months Ended
June 30, 2017
 

Consolidating
Adjustments (1)

   

Consolidating
Adjustments (1)

 
PAA PAGP PAA PAGP
REVENUES $ 8,080 $ $ 8,080 $ 6,078 $ $ 6,078
 
COSTS AND EXPENSES
Purchases and related costs 7,551 7,551 5,320 5,320
Field operating costs 312 312 304 304
General and administrative expenses 80 1 81 68 1 69
Depreciation and amortization 49   1   50   129     129  
Total costs and expenses 7,992 2 7,994 5,821 1 5,822
 
OPERATING INCOME 88 (2 ) 86 257 (1 ) 256
 
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 96 96 68 68
Interest expense, net (111 ) (111 ) (127 ) (127 )
Other income, net 11     11   1     1  
 
INCOME BEFORE TAX 84 (2 ) 82 199 (1 ) 198
Current income tax expense (7 ) (7 ) (1 ) (1 )
Deferred income tax benefit/(expense) 23   (2 ) 21   (9 ) (14 ) (23 )
 
NET INCOME 100 (4 ) 96 189 (15 ) 174
Net income attributable to noncontrolling interests   (89 ) (89 ) (1 ) (149 ) (150 )
NET INCOME ATTRIBUTABLE TO PAGP $ 100   $ (93 ) $ 7   $ 188   $ (164 ) $ 24  
 
BASIC AND DILUTED NET INCOME PER CLASS A SHARE $ 0.05   $ 0.16  
 
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING 157   153  
 

____________________

(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)

 
Six Months Ended
June 30, 2018
Six Months Ended
June 30, 2017
 

Consolidating
Adjustments (1)

   

Consolidating
Adjustments (1)

 
PAA PAGP PAA PAGP
REVENUES $ 16,478 $ $ 16,478 $ 12,745 $ $ 12,745
 
COSTS AND EXPENSES
Purchases and related costs 15,070 15,070 10,912 10,912
Field operating costs 605 605 593 593
General and administrative expenses 159 2 161 142 3 145
Depreciation and amortization 175   1   176   250   1   251  
Total costs and expenses 16,009 3 16,012 11,897 4 11,901
 
OPERATING INCOME 469 (3 ) 466 848 (4 ) 844
 
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 171 171 121 121
Interest expense, net (217 ) (217 ) (256 ) (256 )
Other income/(expense), net 10     10   (4 )   (4 )
 
INCOME BEFORE TAX 433 (3 ) 430 709 (4 ) 705
Current income tax expense (20 ) (20 ) (11 ) (11 )
Deferred income tax expense (25 ) (16 ) (41 ) (65 ) (54 ) (119 )
 
NET INCOME 388 (19 ) 369 633 (58 ) 575
Net income attributable to noncontrolling interests   (325 ) (325 ) (1 ) (509 ) (510 )
NET INCOME ATTRIBUTABLE TO PAGP $ 388   $ (344 ) $ 44   $ 632   $ (567 ) $ 65  
 
BASIC AND DILUTED NET INCOME PER CLASS A SHARE $ 0.28   $ 0.47  
 
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING 157   136  
 

____________________

(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)

 
June 30, 2018 December 31, 2017
 

Consolidating
Adjustments (1)

   

Consolidating
Adjustments (1)

 
PAA PAGP PAA PAGP
ASSETS
Current assets $ 3,852 $ 3 $ 3,855 $ 4,000 $ 3 $ 4,003
Property and equipment, net 14,257 16 14,273 14,089 16 14,105
Goodwill 2,535 2,535 2,566 2,566
Investments in unconsolidated entities 3,116 3,116 2,756 2,756
Deferred tax asset 1,377 1,377 1,386 1,386
Linefill and base gas 866 866 872 872
Long-term inventory 169 169 164 164
Other long-term assets, net 904   (3 ) 901   904   (3 ) 901
Total assets $ 25,699   $ 1,393   $ 27,092   $ 25,351   $ 1,402   $ 26,753
 
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities $ 5,122 $ 2 $ 5,124 $ 4,531 $ 2 $ 4,533
Senior notes, net of unamortized discounts and debt issuance costs 8,937 8,937 8,933 8,933
Other long-term debt 29 29 250 250
Other long-term liabilities and deferred credits 787     787   679     679
Total liabilities $ 14,875 $ 2 $ 14,877 $ 14,393 $ 2 $ 14,395
 
Partners' capital excluding noncontrolling interests 10,824 (9,163 ) 1,661 10,958 (9,263 ) 1,695
Noncontrolling interests   10,554   10,554     10,663   10,663
Total partners' capital 10,824   1,391   12,215   10,958   1,400   12,358
Total liabilities and partners' capital $ 25,699   $ 1,393   $ 27,092   $ 25,351   $ 1,402   $ 26,753
 

____________________

(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

(in millions, except per share data)

 
Three Months Ended
June 30,
Six Months Ended
June 30,
2018   2017 2018   2017
Basic and Diluted Net Income per Class A Share (1)
Net income attributable to PAGP $ 7 $ 24 $ 44 $ 65
Basic and diluted weighted average Class A shares outstanding 157 153 157 136
 
Basic and diluted net income per Class A share $ 0.05   $ 0.16   $ 0.28   $ 0.47
 

____________________

(1)  

For the three and six months ended June 30, 2018 and 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.

 

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